ML19257C804

Responds to NRC 791221 Request for Info Re Main Steam Line Break Accident Analysis.Critical Heat Fluxes Will Not Be Exceeded in Event of Steam Line Rupture.Affected Steam Generator Blows Dry in 104.6 Seconds

ML19257C804
Person / Time
Site:	Calvert Cliffs
Issue date:	01/25/1980
From:	Lundvall A BALTIMORE GAS & ELECTRIC CO.
To:	Reid R Office of Nuclear Reactor Regulation
References
NUDOCS 8001300472
Download: ML19257C804 (36)

Text

{{#Wiki_filter:* 3 BALTIMORE GAS AND ELECTRIC COMPANY P. O. BOX 1475 DALTIMORE. MARYLAN D 21203 January 25, 1980 ARTHun E.LUNDVALL,JR. vict PassiotNT Su rety Office of Nuclear Reactor Regulation U. S. Nuclear Regulatory Commission Washington, D. C. 20555 Attn: Mr. Robert W. Reid, Chief Operating Reactors Branch #h Division of Operating Reactors

Subject:

Calveit Cliffs Nuclear Power Plant Units Nos. 1 & 2, Deckets Nos. 50-317 & 50-318 Automatic Initiation of Auxiliary Feedvater System

References:

(a) NRC letter dated 12/21/79 from R. W. Reid to A. E. Lundvall, Jr., came subject. (b) BG&E letter dated 1/22/80 from A. E. Lundvall, Jr., to H. R. Denton, Request for Amendment to Operating Licenses. Gentlemen: Reference (n) requested that we provide certain information concerning the effect of our proposed automatic auxiliary feedvater initiation design on containment pressure and likelihood of a return to power following a main steam line break. Submitted herein is the infor-mation concerning the main steam line break transient requested in the enclosure of reference (a). We shall not implement our proposed design for the automatic initie. tion of auxiliary feedvater flow until your approval is received. Technical Specifications regarding the automatic initiation of auxiliary feedvater flow were submitted in reference (b). Very truly yours, f'. w b724L I cc: J. A. Biddison, Esquire G. F. Trowbridge, Esquire Messrs. E. L. Conner, Jr. - NRC g jj P. W. Kruse - CE J. W. Brothers - Bechtel 8 0 0130 0 97A ( F

) .a t* REQUEST FOR INFOR!& TION AUT0!% TIC DTITIATION OF T!!E AFWS AFFECT ON }&IN STEAM LINE BREAK ACCIDENT ANALYSIS A. Return to Power 1. Provide the results of analyses of main steam line breaks that are the most limiting with respect to fuel failure resulting from return to power. Analyses should be presented covering: a. Break inside containment b. Break outside containment c. Availability or loss of offsite power Justify omitting an analysis for any of the above. The analysis assumed that the event is initiated by a circumferential rupture of a 34-inch (inside diameter) steam line at the steam generator main steam line nozzle. This break size is the most limiting, since it ce.uses the greatest rate of temperature reduction in the reactor core region. The bre k outside containment cases were not analyzed since these result in less adverse reactivity transient because the break size is smaller due to the flow venturis in each steem line. Loss of offsite power concurrent with a main steam line break (MSLB) has not been part of the design basis as described in the FSAR and, therefore, was not considered. The analysis of the Steam Line Rupture event was perfomed using the same procedures and methods presented in the FSAR and the Unit 2, Cycle 3 license submittal. The two steam line rupture cases considered in conjunction with automatic initiation of auxiliary feedvater flow are: 1. 2 Loop - Full Load (2754MWt) 2. 2 Loop - No Load ( l MWt) The SLB r. vent was analyzed with the assu=ption of a three minute delay between the time of transient initiation and the time when Auxiliary Feedwater (AFW) flow is delivered to the affected steam generator. This is conservative with respect to the expected time of AFW initiation since the generation of the AFW signal actually occurs at the time of the low steam generator water level trip signal. The analysis assumes, therefore, that AFW flow is delivered to the steam generator sooner than the flow is actually available resulting in a conservative prediction of the resulting cooldown. 1819

J 2

Two-Loop 2754 Wt The Two Loop - 2754 W t case was initiated at the conditions listed in Table 1. The Moderator Temperature Coefficient (MIC) of reactivity assumed in the analysis corresponds to end of life, since this MI'C results in the greatest positive reactivity change during the RCS cooldown caused by the Steam Line Rupture. Since the reactivity change associated with moderator feedback varies significantly over the moderator te=peratures covered in the analysis, a curve of reactivity insertion versus temperature, rather than a single value of 2CC, is assumed in the analysis. The moderator cooldown curve given in Figure 1 was conservatively calculated assuming that on renetor scram, the highest worth Control Element Assembly is stuck it; the fully withdrawn position. The reactivity defect associated with fuel temperature decreases is also based on end of life Doppler defect. The Doppler defect based on an end of life Fuel Temperature Coefficient (FTC), in conjunction with the decreasing fuel temperatures, causes the greatest positive reactivity insertion during the Steam Line Rupture event. The uncertainty on the FTC assumed in the analysis is given in Table 1. The p fraction assumed is the maximum absolute value including uncertainties for end of life conditions. This too is conservative since it maximizes suberitical multiplication and thus, enhances the potential for Return-To-Power (R-T-P). The minimic CEA worth assumed to be available for shutdown at the time of reactor trip.at the mimm allowed power level is 6.4%o#. This available scram worth was calculated for the stuck rod which prc-duced the moderator cooldown curve shown in Figure 1. The analysis conservatively assumed that on Safety Injection Actuation signr.1 that one High Pressure Safety Injection pump and one Low Pressure Safety Injection pump fail to start. The analysis also assumed a conservatively low value of the boron reactivity worth of -1.0%4p per 95 PPM. The conservative assumptions on feedwater flow were discussed previously. The feedwater flow and enthalpy as a function of time are presented in Figures 2 and 3 respectively. The response of the NSSS during this event is given in Figures 5 through 9 The results of' the analysis shows the affected steam generator blows dry at 67.6 seconds and thus terminates the cooldown of the RCS. The peak reactivity attained prior to delivery of auxiliary feedwater flow is -0.67%Ap at 71.2 seconds. The delivery of boren via the High Pressure Safety Injection inserts negative reactivity and the total reactivity becomes more negative. The results of the transient quoted so far are same as previously quoted in the Unit 2, Cycle 3 licensing amendment. 1819 313

The delivery of auxiliary feedwater flow starting at 180.0 seconds initiates a further cooldown of the RCS which results in more positive reactivity insertion and an approach to core criticality. However, the approach to criticality is teminated by the additional boron injected via the High and Low Pressure Safety Injection Pumps (one HPSI and one LPSI pumps are assumed operable). The peak reactivity attained is -0.18% AP at 368.4 seconds. The Steam Line Rupture event initiated at HFP conditions shows that prior to delivery of auxiliary feedwater flow the results are the same as reported previously in the Unit 2, Cycle 3 license submittal. The delivery of auxiliary feedwater causes the core reactivity to apprcach criticality, but the additional boron injected via the Safety Injection Pumps terminates the approach to criticality and the core remains sub-critical. "'he results of the analysis show that the core never returns to criticality and in the absence of suberitical multiplication there is no R-T-P. Hence, it can be concluded, as it was in the FSAR and previous license submittals, that critical heat fluxes will not be exceeded. Also the consequences of this event with automatic initiation of auxiliary feedwater are not more adverse than previously reported in the Unit 2, Cycle 3 licensing amend =ent. Two Loop - No Lord Two Loop - no load case was initiated at the conditions given in Table 3 The moderator cooldown curve is given in Figure 10. The cooldown curve corresponds to an end of life MIC. An end of life FTC was also used for the reasons previously discussed in connection with the two loop - 2754 Wt case. The minimum CEA shutdown worth available is conservatively assumed to be the minimum required technical specification limit of 3.4% Ap. A mWm inverse boron worth of 85 PPM /%ar was conservatively assumed for the safety injection during the no load case. The feedwater flow and the enthalpy used in the analysis are presented in Figures 11 and 12 respectively. The reactivity insertion as a function of time is presented in Figure 13 The NSSS response during this event is given in Figures 14 to 18. The results of the analysis shows that the affected steam generator blows dry at 104.6 seconds. The peak reactivity attained during this time period is.61% ap. The addition of boron from the high pressure safety injectf.on adds negative reactivity and thus the core reactivity becomes more negatire. At 180 seconds the auxiliary feedwater flow is delivered to the affected steam generator. This initiates a further cooldown of the RCS. The cooldown of the RCS inserts more positive reactivity. However, Low Pressure Safety Injection flow is initiated at 116.8 seconds which injects additional boron. The negative reactivity added due to boron injection via the LPSI's more than offsets the positive reactivity inserted by the added cooldown of the BCS. Hence the core never reaches criticality after initiation of auxiliary feedwater flow. 1819 314

4-The two loop no load case attains a peak criticality of.61% ap, which occurs before the initiation of auxiliary feedwater. Hence the results of the SLB event with autm.atic initiation of auxiliary feedwater is no worse than the 2 loop - no load case analyzed

• for Unit 2, Cycle 3 without autc=atic initiation of auxiliary feedwater flow.

' Note: The 2 Loop - No Load case with auxiliary feedwater flow was ana-lyzed as part of the present analysis. The results of the 2 Loop - No Load case without auxiliary feedwater flow is not presented in the Unit 2, Cycle 3 license submittal. 2. Provide the time sequence of all actions and events occurring during each of the postulated steam line break transients. These events and actions should include: a. Reactor scram b. Turbine trip c. Steam line isolation d. Feedwater isolation e. H:CS actuation f. Auxiliar/ feedwater actuation and control g. Safety / relief valve actuation (primary and secondarf systens) h. Operator actions (define credit for operator action) 1. Initiation of onsite power (if required). Table 2 presents the sequence of events for the full power case initiated at the conditions given in Table 1. Table 4 presents the sequence of events for the 2-loop no-load case initiated from the conditions given in Table 3 3 For each of the above, identify the initiating signal, the protection system that initiates the action, and the extent of the action ending with the time the element (i.e., PSIV, turbine stop, turbine control, turbine bypass, etc.) reaches its new condition. The above events are to reflect the expected response of the plant and systems. Tables 2 and 4 identify the initiating signals, protection systems and extent of actions for all actions and events occuring during the two-loop full power and two-loop no load steam line break transients, respectively. 4. Identify and justify and equipment that does not meet Regulatory Guides and IEEE-279 requirements. The equipment used in the automatic auxiliary feedwater initiation system meets the requirements of IEEE-279 and the applicable Regulatory Guides for this plant. 1819 315

5 Provide a list of potential single failures that could affect each of the above actions and show how the analyses presented consider the worst single failures from a fuel failure standpoint. Note that nomal control systems should not be considered to function if their action would be beneficial with respect to fuel failures. The MSLB results presented in the FSAR and subsequent reload licensing submittals assumed the following consequential failures in addition to the single failure which initiates the event (i.e., the double ended pipe break inside containment): (a) On reactor scram, the highest worth Control Element Assembly is assumed to stick in the fully withdrawn

position, (b) On Safety Injection Actuation, one of the HPSI and one of the LPSI safety injection pumps are assumed to fail to start.

(c) No main feedwater isolation is assemed on ESIS. The main feed flow is assumed to coastdown to 5% of full power flow in 60 seconds. (More realistically flow would ra=p 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 described above and is consistent with the design basis presented in the FSAR. No consequential failures other than previously identified were considered. All Control systems considered were assumed to function in the manner consistent with the FSAR. Single failures concurrent with the MSLB (other than those identified above), are not, and have not been part of the design basis as des-cribed in the FSAR and, therefore, were not considered. 6. Provide the following infomation as a function of time: a. Minimm DNER b. Cladding temperature if DNER limit is exceeded c. Feedwater flow into faulted and nonfaulted steam generators (main and auxiliary) d. Steam generator liquid mass, heat transfer area covered, heat transfer rate, and pressure e. Break flow rate f. Other steam release rates in secondary systems g. Primary system pressure h. Pressurizer level

i. Hot channel flow rate

}h}h 3}h

.. j. Core inlet and outlet te=perature k. Pressurizersafety/reliefvalveflowrate 1. ECCS flow rate. The analysis should be carried out until the effects of delayed neutrons and moderator feedback have turned around and the suberiticality margin is increasing. Note the DNER calculations must reflect the initial plant perturbations due to moderator and pressure decrease and loss of offsite power (if appropriate). Also discuss how the effects of a stuck rod are considered when calculating DNERs after the rods have been inserted. If fuel damage occurs (i.e., violation of DNBR), provide fraction of fuel that failed anc offsite dose calculations. Also provide and justify DNB correrlations used in the analyses. DIGR calculations _ were not applicable for this analysis as the critical heat flex was not approached during the transient. Since DNER limit was not exceeded, no curve for cladding temperature or hot channel flow rate versus time were developed. A conservatively high value of the AFW flow was calculated assuming that all auxiliary feedwater pumps are oper-ble. An AFW flow value of 20% of full power feedwater flow was used in the analysis. This value accounts for pump run-out due to reduced back pressure. In addition, the analysis conservatively assumed that all the AFW flow is fed only to the damaged steam generator. The analysis conservatively assumed that there is no main feedwater isolation when the Main Steam Isolation Signal (MSIS) is actuated. Hence, the main feedwater flow is ramped down to 5% of full power feed-water flow in 60 seconds (A mere realistic =ain feedwater flow would ramp down to zero in 20 seconds). This assu=ption is conservative because it prolongs the cooldown of the RCS and thus results in a more severe reactivity transient. Figure 9 presents the steam generator pressure response for the full load analysis. Figure 18 presents the steam generator pressure response for the no load steam line break analysis. Figures 8 and 17 present the change in time of the primary system pressure for the full power and no load steam line break events respectively. Figures 7 and 16 show the change in time of the core inlet, outlet and average temperature for the full power and no load steam line break events respectively. No initiation of pressurizer safety or relief occurs during the full power or no load steam line break transients. HPSI flow is assumed to be 1280 gym and LPSI flow is assumed to be 200 gpm. i 819

M 7

., 3. Containment Pressure 1. Review your current analysis of this event, and provide NRC with the assu=ptions used during this analysis. Particular e=phasis should be placed on describing how AFS flow was accounted for in your original analysis. (Reference to previously submitted infomation is acceptable if identified as to page number and date). Any changes in your design which could impact the ccnclusions of your original analysis should be discussed. We are particularly concerned with design changes that could lead to an underestimation of the con-tairment pressure following a MSLB inside containment. The AFW rate was assumed to be independent of the steam generator pressure. This is an appropriate assumption for these analyses since the ruptured steam generator pressure is coupled to the containment pressure after 180 seconds. The AFW flow rates used are consistent with pressures of approximately 50 psia. The AFW flow rate was assumed to be 2200 GPM for the ruptured steam generator only. No AFW flow was assumed for the intact steam generator. This assumption is not based on any operator action; rather,.it is based on CE experience with cross-connected AFW networks when the steam generator pressures differ significantly. Under these conditions, the AFW is typically diverted totally to the low pressure (i.e., ruptured) steam generator. This assumption also provides the maximum potential inventory to the containment since any AFW sent to the intact unit is not available to the containment. Auxiliary feedwater systen operation was not included in the original analysis. Therefore, changes in the configuration and operation of the auxiliary feedwater system would have no impact on the original analysis. A 20% moisture carry-over assumption (ruptured SG only) was used. 2 This reanalysis was perfomed for the 6.30 ft, 223,000 lbs no load case, as was the original analysis. 2. Provide the following infomation for the reanalyses perfomed to detemine the ~hm containment pressure for a spectrum of postulated main steam line breaks for various reactor power levels for the proposed AFS design. a. Specify the AFS flow rate that was used in your original con-tainment pressurization analyses. Provide the basis for this assumed flow rate. No auxiliary feedwater flow was included in the original contairment pressure analysis. Initiation of the auxiliary feedwater system to mitigate the consequences of a main steam line break was not required, and thus was not included in this

analysis, b.

Provide the rated flow rate, the run out flow rate, and the pump head capacity curve for your AFS design. 1819 318

.. Rated flow rate is 700 gpm at 2490 ft. Run out flow rate was calculated to be 2200 gpm. The pump head capacity curve is attached as Document 12083-06 En. 2. c. Provide the time span over which it was assumed in your original analysis that AFS was added to the affected steam generator following a MSLB inside contain=ent. Not applicable. d. Discuss the design provisions in the AFS used to teminate the AFS flow to the affected steam generator. If operator action is required to perfom this function, discuss the information that will be available to the operator to alert him of the need to isolate the auxiliary feedwater to the affected steam generator, the time when this infomation would become available, and the time it would take the operator to complete this action. Define credit for operator action. If temination of AFS flow is dependent on automatic action, describe the basic operation of the auto-isolation syst-m. Describe the failure modes of the system. Describe any annunciation devices associated with the system. It was assumed that the operator initiated AFW at 180 seconds after the start of the event. The analyses were run to 1000 seconds, where the steamirg rates had dropped well below the containment heat removal capability. At 1000 seconds, the level of the mptured unit had not fully recovered, so no credit was taken for operator action; in other words,-the AFW was not isolated once it had been initiated. e. Provide the single active failure analyses which specifically identifies those safety grade systems and components relied upon to limit the mass and energy release and the containment pressure response. The single failure analysis should include, but not necessarily be limited to: partial loss of containment cooling systems and failure of the AFS isolation valve to close. The no load case was selected since it was the worst MSLB case for containment sizing calculations, via the FSAR analysis. The reason that the no load case was the worst is that the steam generator inventory at no lead conditions exceeds the full load inventory plua main feedwater contributions. As described in d. above, AFW was not isolated once it had been initiated. The initial conditions for this analysis are identical to those specified in FSAR Section 14.16.3 f. For the single active failure case which results in the maximum containment atmosphere pressure, provided a chronology of evenes. Graphically, show the containment atmosphere pressure as a function of time for at least 30 minutes following the accident. For this case, assume the AFS flow to the broken loop steam generator to be at the pump run out flow (if a run out control system is not part of the current design) for the entire transient if no auto-matic isolation to auxiliary feedwater is part of the current design. 1819 319

Figure 19 presents the containment atmosphere pressure as a function of time for upwards of 15 minutes following the initiating event. Auxiliary feedwater flow feeding the ruptured steam generator was assumed to be 2200 gpm. g. For the case identified in (f) above, provide the mass and energy release data in tabular fom. Discuss and justify the assu=ptions made regarding the time at which active contairment heat removal systems beccme effective. For the first 70 seconds, the mass / energy release data is the same as the FSAR data (see attached table 5). At 180 seconds the AFW was initiated,andtheresultingmass/energyreleaserateswereas shown in Table B. 1819 320

TABLE 1 KEY PARAMETERS ASSUMED IN THE IMIN STEAM LINE BREAK EYF,NT WITH AUT0fMTIC INITIATION OF AUXILIARY FEEDWATER SYSTEM (2 LOOP - FULL LOAD CONDITION) Unit 2, Cycle 3 License Submittal Present Analysds Parameters Units Values Values Initial Core Power Level MWt 2754.0 2754.0 Initial Core Inlet Temperature F 550.0 550.0 Initial RCS Pressure psia 2200.0 2200.0 Initial Steam Generator Pressure psia 861.0 861.0 Low Steam Pressure Trip Setpoint psia 478.0 478.0 Safety Injection Actuation psia 1578.0 1578.0 Setpoint High Pressure Safety Injection psia 1280.0 1280.0 Flow Delivery Low Pressure Safety Injection psia 200.0* 200.0 Flow Delivery CEA Worth at Trip %Ao -6.4 -6.4 Moderator Cooldown Curve %Ao vs. F Figure 1 Figure 1 Doppler Multiplier 1.15 1.15 Inverse Boron Worth PPM /%ao 95.0 95.0 Feedwater Flow BTV/sec vs. Sec Figure 2 Figure 2 Feedwater Enthalpy BTU /lbm vs. Sec Figure 3 Figure 3 No credit for Low Pressure Safety Injection was taken for the Unit 2, Cycle 3 license subaittal analysis. 1819 321

I l N TABLE 2 l Sequence of Events for the Main Steam Line Break Event with Automatic Initiation of Auxiliary Feedwater System (Full load, Two-Loop Condition, Nozzle Break) Time (sec.) Event Safety System Initiated Setpoint or Value .0.0 Initiation of break 3.4 Low steam Generator Pressure Reactor Protection System 478 psia trip signal occurs, MSIS Main Steam Isolation System initiated and Main Steam Isolation Valves begin to close. ~ 4.3 Trip breakers open ~ 4.8 CEAs begin to drop into Reactor Protection System core ~ 10.5 Conplete closure of Main Steam Isolction Valves to terminate blowdown from the intact steam generator 15.2 Pressurizer empties 15.5 Low RCS pressure, SIAS Safety Injection System 1578.0 psia Initiated 21.2 High Pressure Safety Safety Injection System 1280.0 Injection flow Initiated 64.8 Main feedwater flow completes ramp down to 5% 67.2 Affected steam generator liquid inventory depleted and beginning of blowdown of feedwater only 71.2 Peak Reactivity Prior to -0.67% Delivery of Auxiliary Feedwater Flow 1819 322 ~

TABLE 2 (Continued) Time (sec.) Event Safety System Initiated Setpoint or value 180.0 Auxiliary Feedwater flow to affected steam generator initiated 345.2 Low Pressure Safety Safety. Injection Systen 200 psia Injection flow initiated 368.4 Peak reactivity post -0.18%Ao auxiliary feedwater delivery M e 1819 323

TABLE 3 KEY PARNtETERS ASSUMED IN THE MAIN STEAM LINE BREAK EVENT WITH AUTOMATIC INITIATION OF AUXILIARY FEEDWATER SYSTEM (2 LOOP - NO LOAD CONDITION) Unit 2, Cycle 3 Present Analysis Parameters Units Values Values Initial Core Power Level MWt i I Initial Core Inlet Temperature

• F 532.0 532.0 Initial RCS Pressure psia 2200.0 2200.0 Initial Steam Generator Pressure psia 899.0 899.0 Low Steam Pressure Trip Setpoint psia 478.0 478.0 1578.0 1578.0 Safety Injection Actuation psia Setuoint High Pressure Safety Injection psia 1280.0 1280.0 Flow Delivery 200.0*

200.0 ~ Low Pressure Safety Injection psia Flow Delivery -3.4 -3.4 CEA Worth at Trip tap Moderator Cooldown Curve %Ao vs. F Figure 10 Figure 10 Doppler Multiplier 1.15 1.15 Inverse Boron Worth PPM /%ac 85.0 85 0 Feedwater Flow BTU /sec vs. Sec Figure 11 Figure 11 Feedwater Enthalpy BTU /lbm vs. Sec Figure 12 Figure 12 No credit for Low Pressure Safety Injection was taken for the Unit 2, Cycle 3 license submittal analysis. 1819 324

~ i N TABLE 4 1 Sequence of Events for the Main Steam Line Break Event I with Automatic Initiation of Auxiliary Feedwater System (N6 load, Two-Loop Condition, Nozzle Break} l Time (sec.) Event Safety System Initiated Setooint or Value .0.0 Initiation of break 3.7 Low steam Generator Pressure Reactor Protection System 478 psia trip signal occurs,ftSIS Main Steam Isolation System initiated and Main Stean Isolation Valves begin to close. 4.6 Trip breakers open ~ 5.1 CEAs begin to drop into Reactor Protection System core 10.7 Conplete closure of Main Steam Isolation Valves to terminate blowdown from e e intact steam generator 12.3 Pressurizer empties 15.7 Low RCS pressure, SIAS Safety Injection System 1578.0 Initiated 20.9 High Pressure Safety Safety Injection System 1280.0 Injection flow Initiated 104.6 Affected steam generator liquid inventory depleted and beginning of blowdown of feedwater only 108.2 Peak Reactivity -0.61%ac i819 725

e TABLE 4 (Continued) Time (sec.) Event Safety System Initiated Setooint or Value 116.8 Low Pressure Safetv Injection Safety Injection System flow initiated 180.0 Auxiliary Feedwater flow 200.0 psia to affected steam generator initiated h 9 e d O e 1819 326-T

TABLE 5 No Ioad, One kop, Nozzle Break 223,000 lb, 20% Moisture content Time Secondary Blow Max Secondary Blow Max Total Total Press. Down Blow Down Max Discharge Discharge Discharge See Press. Down Ib x 10 PSIA Rate Ib x 10 Rate 1bu PSIA Rate lbs/see 1bs/s. lbs/see 105 0 900 13320 900 266h 1598h 1 771 10700 .1179 823 2h32 25h8 13132 .1438 2 606 8902 .215 758 2236 h882 11138 .264 3 519 7620 .296 702 2068 703h 9688 .366 h h54 6661 .366 653 1922 9029 8583 .456 5 h03 5920 .426 610 1792 10886

7712, 535 6

366 5369 .h81 5T1 1678 12621 70h7 .607 7 337 4948 532 537 1576 1h2h2 652h .67h 8 315 h639 578 505 1h80 15776 6114 736 9 298 h382 .622 h38 988 17010 5370 799 10 287 h225 .66h h77 5 17507 h230 .B: 20 258 3794 1.05 0 379h 1.2 30 198 2983 1.38 2983 1 56 40 16h 2h31 1.6h 2h31 1.72 50 1h1 209h 1.87 209h 2.05 60 122 1817 2.06 1817 2.2h 70 108 1610 2.176 1610 2.361 80 98 0 0 90 98 0 0 1819 327

TABLE B STEA!!!!!G DATA RE: 301 1mb/sec AF11 Time Steam Rate Specific Enthalpy (sec) lbm/sec. Btu /lbn. 130. 301. 1198.0 200.' 301. 1171.0 250. 301. 1171.1 300. 301. 1170.7 350. 301. 1170.0 400. 301. 1173.7 420. 301. 1171.1 445. 301. 1172.0 455. 29 3. 1171.6 465. 275. 1171.9 485. 270. 1172.0 500. 264. 1172.2 550. 245. 1171.7 600. 219. 1171.4 650. 187. 1170.0

700, 149.

1170.0 750. 111. 1170.0 800. 72. 1170.0 850. 52. 1169.3 900. 36. 1168.6 950. 27. 1165.0 1000. 21. 1166.2 1819 328

7,5 2 LOOP - FULL LOAD 7,0 6.0 m 5.0 ~ se i 4.0 o P E 3,0 >-b 2: t3$ 2.0 = 1.0 0,0 1819 729 -0,5 i 200 300 400 500 600 MODERATOR TEMPER ATURE, F BALTIMORE F3 " GAS & ELECTRIC CO. STEAM LINE RUPTURE EVENT 9 1 Coivert Cli"' REACTIVITY INSERTION vs MODERATOR TEMPERATURE Nuclear Power Plant

1 1700 \\ 2 LOOP - FULL LOAD 1500 i 1000 AFFECTED AND UNAFFECTED STEAll D GENERATOR WITH AND WITHOUT 3 AUXILIARY FEEDWATER FLOW N - cd 5 CE ~ iE AFFECTED STEAM GENERATOR WITH AUXILIARY FEEDWATER FLOW 500 UNAFFECTED SG WITH Af!D WITHOUi AUXILIARY FEEDWATER AND AFFECTED SG WITHOUT AUXILIARY FEEDFATER FLOW 0 0 100 200 300 400 500 1819 530 TIME, SEC0f!DS BALTIMORE R* GAS & ELECTRIC CO. STEAM LINE RUPTURE EVENT 9 FEEDWATER FLOW VS TIME 2 Nuc e w Plant

6 500 2 LOOP - FULL LOAD 400 5 ~ as AFFECTED AND UNAFFECTED SG WITH AND WITHOUT 300 g' AUXILIARY FEEDWATER FLOW d E w g 200 GE wtt 100 0 0 100 200 300 400 500 TIME, SECONDS 1819 331 BALTIMORE GAS & ELECTRIC CO. STEAM LINE RUPTURE EVENT Figure sucI,$*Eow[Aan, FEEDWATER ENTHALPY VS TIME 3

7 2 LOOP - FULL LOAD M0DERATOR 5 t 3 DOPPLER o_' ,.16 / ~ ~ BORON ~ h -1 Q ac TOTAL \\ w e _3 -5 L-CEAs -7 i i i 0 100 200 300 400 500 TIME. SEC0tJOS 1819 432 BALTIMORC A " S GAS & ELECTRIC CO. STEAM LINE RUPTURE EVENT Coivert Cli"' REACTIVITY vs TIME Nuclear Power Plant

I 120-- 2 LOOP - FULL LOAD ,h 100 '-- 8 ~ N Bi + 60 Eo5 a. g' 60 E 2 g 8 40 20 \\ 'N O I 0 100 200 300 400 S00

TIME, SECONOS 1819

'33 c-BALTIMORc Fi ure S GAS & RECTUC CO. STEAM 1.INE RUPTURE EVENT coiveri ciirr' CORE POWER vs TIME Nuclect Power Plant

I 120 2 LOOP - FULL LOAD 100 ~ B 8 m 80 b !E >l 60 m-W w 40 o 20 ~ \\ 0 I I O 100 200 300 400 500 TIME. SECONOS 1819 334 BALT U.40RE gas & ELECTRIC CO. STEAM LINE RUPTURE EVENT "D"'" 6 CORE AVERAGE HEAT Fl.UX vs TIME Nuc e v

Plan,

700 2 LOOP - FULL LOAD aw T c 600 7 OUT 1 wy TAVG ay 500 .T ~ M IN E 5 i ~ 4 0 0 '- 300 200 I I I i 0 100 200 300 400 500 ~ ~ TIME. SECONCS 1819 735 m STEAM LINE RUPTURE EVENTS Figure GAS ELE T IC CO. coivert cirrr5 RCS TEMPERATURES vs TIME 7 Nuclear Power Plant

2400 2 LOOP - FULL LOAD t 2000 ~ 5 w c-16C0 i oea LO . '.. 1200 0 E c_ GQu 800 \\ 400 0 I I r I O 100 200 300 400 500 TIME. SEC0tCS 1819 336 8 " 8 STEAM LINE RUPTURE EVENT GAS ELE T IC CO. coivert cli RCS PRESSURE vs TIME Nuclect Power Plant

900 2 LOOP - FULL LOAD 750 5 E 500 E i$ o i UNAFFECTED S.G. 'g 450 c. 300 150 N AFFECTED S.G. 0 0 100 200 300 400 500

TIME, SECONOS 1819 337 BALTIMORE STEAM LINE RUPTUR E EVENT Figure GAS & ELECT STEAM GENERATOR PRESSURE vs TIME 9

~ e,,, t C i Nucleer Power Plant

e 5,0 2 LOOP - NO LOAD ~ 4.0 3,0 E p 5 w5 2.0 C 5'W ~~ 1.0 0,0 t t t -3,0 200 300 400 500 600 MODERATOR TEMPERATURE, UF 1819 338 BALTIMORE GAS & ELECTP.!C CO. STEAM LINE RUrTURE EVENT p'9" .wcIc$Sw[Aan, REACTIVITY INSERTION vs MODERATOR TdMPERATURE 10

d 500 2 LOOP - NO LOAD AFFECTED SG HITH AUXILIARY FEEDWATER FLOW 400 $E5 300 ~ i g UNAFFECTED SG UITH AND WITHOUT g 200 AUXILIARY FEEDWATER AND AFFECTED SG WITHOUT AUXILIARY d FEEDWATER FLOW 100 0 0 100 200 300 400 500 TIME, SECONDS ]8]9 339 R " GAS ELECT IC CO. STEAM LINE RUPTURE EVENT 9 socIIr*S.N"Acn, FEEDWATER FLOW VS TIME 11

S 100 2 LOOP - NO LOAD 90 80 55q 70 E 60 it AFFECTED AND UNAFFECTED SG 50 WITH AND WITHOUT sE AUXILIARY FEEDWATER FLOW w 40 aW 30 20 10 0 0 100 200 300 400 500 TIME, SECONDS

g;g 7g

^ R" GAS E T IC CO. STEAM LINE RUPTURE EVENT S FEEDWATER ENTHALPY VS TIME 12 w Plant Nuc e

3

5. 0

2. LOOP - NO LOAD y,g 3.0 MODERATOR 2.0 1.0 g

DOPPLER 0.0 C E -1.0 b -2.0 TOTAL BORON -3.0 CEAs N -4.0 -5.0 s -6.0 0 100 200 300 400 500 1819

1. 41 2

TIME, SECONDS ^ STEAM LINE RUPTURE EVENT Rsure GAS E T IC CO-REACTIVITY vs TIME 13 Coivert cliff, Nuclear Power Plant

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E 8

%g 80 i-Eo ~ Ei c-60 Na2 g 40 o 0 20 0 I i r i 0 100 200 300 400 500 TIME. sEc0N0s 1819 542 ~ BALTIMORE Reure 3AS & ELECTRIC CO. STEAM LINE RUPTURE EVENT 14 Calvert Cliffs CORE POWER vs TIME Nuclear Power Plant

120 2 LOOP - NO LOAD E 100 E 8N u_o 80 t3 !E 6 0 r- %W w 40 o 20 0F O 100 200 300 400 500 TIME. SECON05 1819 343 "S"'* GAS I.E T IC CO. STEAM LINE RUPTURE EVENT co. vert ciirts CORE AVERAGE HEAT FLUX vs TIME Nucl,:cr Power Plant

600 2 LOOP - N0' LOAD 525 u. awa 450 .w we D 375 Ca: E r .a 300 225 150 I I i 0 100 200 300 400 500 TIME. SECONOS 1819 344 l I BALTIMORE STEAM LINE RUPTURE EVENT Figure GAS & ELECTRIC CO. Coiv-rt Ciitri RCS TEMPERATURES vs TIME 16 Nuclear Power Plant

2400 2 LOOP - NO LOAD 2000 c: w c-1600 l l W c:: 2 m w 1200 l cc eo(* 800 400 - / 0 I I i r 0 100 200 300 400 500

TIME, SECONOS

+ 1819 345 As $^ ELE T IC CO' STEAM LINE RUPTURE EVENT Figure coivert cirrr, RCS PRESSURE vs TIME luclect Power Plent

,g e s *g = ,e at a 900 2 LOOP - NO LOAD 750 cr i 69 600 ll} CL tu i

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_~-aa 00y 450 c_ 4 C 300 i UNAFFECTED 5.G. 150 - AFFECTED S.G. I O I ~ 0 100 200 300 400 500 TIME. SE00h0S 1819 346 BALTIMORE GAS & ELECTRIC CO* STEAM LINE RUPTURE EVENT Figure Colvert Clins STEAM GENEP ATOR PRESSURE vs TIME 18 Nuclear P:wer Plant

Fa uRE 19 5 ESTit1ATED C0tiTAll;t1EllT RESP 0!iSE TO ADDITIO!!AL I1 ASS /Ef1ERGY DATA 1 p !lf_ ~ .Q_ _1. j - - 3 c=- -S CE estimates that the containment pressure vs time curve will be qualitatively p{-- q ~~~ ~~ as follows: --r. g -. 7- -,-. - r - - q .l @f . _j.. .... j ; _ .c 4 .l 2 % i _ _. n 1. ~t i. i j s .l_ E @ln ~ __b [. .f - ALF (cp.c.u tre,re D. To e4 !: .[..l_ i y" r-s, y.o i T- 'l ~ ~ ~- ~~3-d-~- PSI ~[ U:5 f. ~ ._ _q. ggg7.. j g g, g ) ..l._. .j. __ _ j. gl E _J i c0 V I l _L I. _. _ [_ _. I l__ _ _ }_ _ _. ! ~ y ._ f .l l l .Y.. 3 Il--N--- .L --- L-L- -i- --f. H-' '-, 30_ 1 T--- _g _ c'... 4.. ... k...[j ...b 1 ..I _..i% M..J N'IT ATIC rd h t f l _ I. _ I' f 1 i ]- a. i. s :l ....p. _ _7 . t_. _..... L i

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