ML20211C644

Proposed Tech Specs,Modifying RPS & ESFAS Trip Setpoint & Allowable Values for SG Low Pressure

ML20211C644
Person / Time
Site:	Arkansas Nuclear
Issue date:	09/23/1997
From:	ENTERGY OPERATIONS, INC.
To:
Shared Package
ML20211C628	List: 2CAN099703, Application for Amend to License NPF-6,modifying RPS & ESFAS Trip Setpoint & Allowable Values for SG Low Pressure ML20211C644
References
NUDOCS 9709260261
Download: ML20211C644 (92)

Text

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PROPOSED TECIINICAL SPECIFICATION CHANGES 9709260261 970923 PDR ADOCK 05000360 P

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TABLE 2.2-1 REACTOR PROTECTIVE INSTRUMENTATION TRIP SETPOINT LIMITS FUNCTIONAL UNIT TRIP SETPOINT ALI4HABLE VALUES 1.

Manual Reactor Trip Mot Applicable Not Applicable 2.

Linear Power Level - High a.

Four Reactor Coolant Pumps 5 110% of RATED THEMIRL POWER S 110.712% of RATED THE3WRL POWER Operating b.

Three Reactor Coolant Pumps Operating c.

Two Reactor Coolant Pumps Operating - Same Loop d.

Two Reactor Coolant Pumps Operating - Opposite Loops 3.

Logarithmic Power Level -

High (1) 5 0.75% of RATED THERMAL POWER S 0.819% of RATED THEpWEL POWER 4.

Pressurizer Pressure - High s 2362 psia s 2370.887 psia 5.

Pressurizer Pressure - Iow 2 1717.4 psia (2) 2 1686.3 psia (2) 6.

Containment Pressure - High s 18.3 psia s 18.490 psia 7.

Steam Generator Pressure - Low 2 712 psia (3) 2 699.6 psia (3) l 8.

Steam Generator Level - Low 2 23% (4) 2 22.111% (4)

• These values left blank pending NRC approval of safety analyses for operation with less than four reactor coolant pumps operating.

ARKANSAS - UNIT 2 2-5 Ameuxhment No. 9,34,46,H3,446,

3/4.3 INSTRUMENTATION 3/4.3.1 REACTOR PROTECTIVE INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.1.1 As a minimum, the reactor protective instrumentation channels and bypasses of Table 3.3-1 shall be OPERABLE.

l APPLICABILITY: As shown in Table 3.3-1.

ACTION:

As shown in Table 3.3-1.

SURVEILLANCE REQUIREMENTS 4.3.1.1.1 Each reactor pertt?'fve instrumentation. channel shall be demonstrated 0FERABLE by tJe % 1a mance of the CHAh;IEL CHECX, CHANNEL CALIBRATION and CHANNEL rum Flt& % TEST operations for the MODES and at the frequencies shown in Table 4.3-1.

4.3.1.1.2 The logic for the bypasses shall be demonstrated OPERABLE prior to each reactor startup unless performed during the preceding 92 days. The total bypass function shall be demonstrated OPERABLE at least once per 18 months during CHANNEL CALIBRATION testing of each channel affected by bypass operation.

4.3.1.1.3 The REACTOR TRIP SYSTEM RESPONSE TIME of each reactor trip function shall be demonstrated to be within its lindt at least once per 18 months. Neutron detectors are exempt from response time testing.

Each test l

shall include at least one channel per function such that all channels are tested at least once every N times 18 months where N is the total number of redundant channels in a specific reactor trip function as shown in the " Total No. of Channels" column of Table 3.3-1.

4.3.1.1.4 The core Protection Calculator System shall be deterndned OPERABLE at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> by verifying that less than three auto restarts have occurred on each calculator during the past 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

4.3.1.1.5 The affected Core Protection Calculator Channel shall be subjected to a CHANNEL FUNCTIONAL TEST to verify OPERABILITY within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of receipt of a valid CPC Cabinet High Temperature alarm.

ARKANSAS - UNIT 2 3/4 3-1 Amendment No. G4,4M,446,

l 4

THIS PAGE IS INTENTIONALLY LEFT BLANK l

ARKANSAS - UNIT 2 3/4 3-6 Amendment No.

INSTRUMENTATION 3/4.3.2 ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.2.1 The Engineered Safety Feature Actuation System (ESTAS) instrumentation channels and bypasses shown in Table 3.3-3 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip setpoint column of Table 3.3-4.

l APPLICABILITY: As shown in Table 3.3-3.

ACTION:

a.

With an ESFAS instrumentation channel trip setpoint less conservative than the value shown in the Allowable values column of Table 3.3-4, declare the channel inoperable and apply the applicable ACTION requirement of Table 3.3-3 until the channel is restored to OPERABLE status with the trip setpoint adjusted consistent with the Trip Setpoint value.

b.

With an ESTAS instrumentation channel inoperable, take the ACTION shown in Table 3.3-3.

i l

SURVEILLANCE REQUIREMENTS 4.3.2.1.1 Each ESEAS instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL CALIBRATION and CHANNEL FUNCTIONAL TEST operations for the MODES and at the frequencies shown in Table 4.3-2.

4.3.2.1.2 The logic for the bypasses shall be demonstrated OPERABLE during the at power CHANNEL FUNCTIONAL TEST of channels affected by bypass operation. The total bypass function shall be demonstrated OPERABLE at least once per 18 months during CHANNEL CALIBRATION testing of each channel af fected by bypass operation.

4.3.3.1.3 The ENGINEERED SAFETY FEATURES.'ESPONSE TIME of each ESTAS function shall be demonstrated to be within the limit at least once per 18 months.

Each test shall include at least one channel per function such that all channels are tested at least once every N times 18 months where N is the total number of redundant channels in a specific ESrAS function as shown in the " Total No. of Channels" column of Table 3.3-3.

ARKANSAS - UNIT 2 3/4 3-10 Amendment No.

f.

i TABLE 3.3-4 (Continued)

ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION TRIP VALUES i

ALLOWABLE FUNCTIONAL UNIT TRIP VALUE VALUES 4.

MAIN St4AM AND FEEDWATER ISOLATION (MSIS) a.

Manual (Trip Buttons)

Not Applicable Not Applicable b.

Steam Generator Pressure - Low 2 712 psia (2) 2 699.6 psia (2) l S.

CONTAINMENT COOLIUG (CCAS) a.

Manual (Trip Buttons)

Not Applicable Not applicable b.

Containment Pressure - High 5 18.3 psia s 18.490 psia c.

Pressurizer Pressure - Low 2 1717.4 psia (1) 2 1686.3 psia (1) 6.

RECIRCULATION (RAS) a.

Manual (Trip Buttons)

Not Applicable Not Applicable b.

Refueling Water Tank - Low 54,400 i 2,370 gallons between 51,050 and 58,600 (equivalent to 6.0 i 0.5%

gallons (equivalent to indicated level) between 5.111% and 6.889%

indicated level) 7.

LOSS OF POWER a.

4.16 kv Emergency Bus Undervoltage (Loss of Voltage) 3120 volts (4) 3120 volts (4) b.

460 volt Emergency Bus Undervoltage 423 i 2.0 volts 423 i 4.0 volts (Degraded Voltage) with an 8.0 i 0.5 with an 8.0 i 0.8 second time delay second time delay ARKANSAS - UNIT 2 3/4 3-17 Amen h nt No. 34,444,444,449,

1 i

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l TABLE 3.3-4 (Continued)

)

l ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION TRIP VALUES ALLOWABLE FUNCTIONAL UNIT TRIP VALUE VALUES 8.

EMERGENCY FEEDWATER (EFAS) a.

Manual (Trip Buttons)

Not Applicable Not Applicable b.

Steam Generator (A&B) Level-Low 2 23% (3) 2 22.111% (3) c.

Steam Generator AP-High (SG-A > SG-B) s 90 psi s 99.344 psi d.

Steam Generator AP-High (SG-B > SG-A) s 90 psi 5 99.344 psi e.

Steam Generator (A&B) Pressure - Low 2 712 psia (2) 2 699.6 psia (2) l (1) value may be decreased manually, to a minimum of 2 100 psia, during a planned reduction in pressurizer pressure, provided the margin between the pressurizer pressure and this value is maintained at s 200 psis the setpoint shall be increased automatically as pressurizer pressure is increased until the trip set-point is reached. Trip may be manually bypassed below 400 psia; bypass shall be autoanatically removed whenever pressurizer pressure is 2 500 psia.

(2)

Value may be' decreased manually during a planned reduction in steam generator pressure, provided the margin between the steam generator pressure and this value is maintained at s 200 psis the setpoint shall be increased automatically as steam generator pressure is increased until the trip setpoint is reached.

(3)

% of the distance between steam generator upper and lower level instrument nozzles.

(4)

Inverse time relay set value, not a trip value. The zero voltage trip will occur in 0.75 1 0.075 seconds.

ARKANSAS - UNIT 2 3/4 3-18 Amendment No. 9,34,46,

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1 THIS PAGE IS INTENTIONALLY LEIT BLANK I

ARKANSAS - UNIT 2 3/4 3-19 Amendment No. 44t,

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THIS PAGE IS INTENTIONALLY LEFT BLANK l

ARKANSAS - UNIT 2 3/4 3-20 Amendment No. 49,4 M,

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60 70 80 90 100 110 120 130 140 150 CONTAINMENT AVERAGE AIR TEMPERATURE ('F)

CONTAINMENT INTERNAL PRESSURE vs.

AVERAGE AIR TEMPERATURE FIGURE 3.6-1 NOTE:

Instrument Error is not Included on Curve ARKANCAS - UNIT 2 3/4 6-7 Amendment No. 9,G4,449,446,

1 3/4.3 INSTRUMENTATION aAsEs 3/4.3.1 and 3/4.3.2 PROTECTIVE AND ENGINEERED SAFETY TEATURES (ESP)

INSTRUMENTATION The OPERABILITY of the protective and EST instrumentation systems and bypasses ensure that 1) the associated ESr action and/or reactor trip will be initiated when the parameter monitored by each channel or combination thereof reaches its setpoint, 2) the specified coincidence logic is maintained, 3) sufficient redundancy is maintained to permit a channel to be out of service for testing or maintenance, and 4) sufficient system functional capability is available for protective and EST purposes from diverse parameters.

The OPERABILITY of these systena is required to provide the overall reliability, redundancy and diversity assumed available in the facility design for the protection and mitigation of accident and transient conditions. The integrated operation of each of these systems is consistent with the assumptions used in the accident analyses.

The surveillance requirements specified for these systena ensure that the overall system functional capability is maintained comparable to the original design standards. The periodic surveillance tests perforned at the minimum frequencies are sufficient to demonstrate this capability. The triannual channel functional testing frequency is to be performed on a STAGGERED TEST RASIS.

The measurement of response time at the specified frequencies provides assurance that the protective and EST action function associated with each channel is completed within the time limit assumed in the accident analyses.

The RPS and ESTAS response time tables have been relocated to the Safety Analysis Report (SAR). No credit was taken in the analyses for those channels with rssponse times indicated as not applicable.

Response time may be demonstrated by any series of sequential, overlapping or total channel test measurements provided that such testa demonstrate the total channel response time as defin.ed.

Sensor response time verification may be demonstrated by either 1) in place, onsite or offsite test measurements or 2) utilizing replacement sensors with certified response times.

I ARKANSAS - UNIT 2 B-3/4 3-1 Amendment No. M,49,M4,

i 6

l hiARKUP OF CURRENT ANO 2 TECHNICAL SPECIFICATIONS i

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i TABLE 2.2-1 REACTOR PROTECTIVE INSTPUMENTATION TRIP SETPOINT LIMITS i

EUNCTIONAL UNIT TRIP SETPOINT ALLOW'\\BLE VALUES i

L 1.

Manual Reactor Trip Not Applicable Not Applicable i

L i

2.

Linear Power Level - High i

t t

a.

Four Reactor Coolant Pumps 5 110% of RATED THERMAL POWER S 110.712% of RATED THENEL POWER Operating

(

b.

Three Reactor Coolant Punps 6

Operating

{

c.

Two Reactor Coolant Pumps t

Operating - Same Loop l

d.

Two Reactor Coolant Pumps l

Operating - Opposite Loops 3.

Logarithmic Power Level -

High (1) j s 0.75% of RATED THERMAL POWER s 0.819% of PATED THENRL POWER 4.

Pressurizer Pressure - High 5 2362 psia 5 2370.887 psia 4

5.

Pressurizer Pressure - Low 2 1717.4 psia (2) 2 1686.3 psia (2) i 6.

Containment Pressure - High s 18.3 psia s 18.490 psia f

7.

Steam Generator Pressure - Low 2 7 g % psia (3) 2 699.f2". !!! psia (3) l!

4 j

8.

Steam Generator Level - Low 2 23% (4) 2 22.111% (4) l 4

0 These values left blank pending NRC approval of safety analyses for operation with lecs than four reactor coolant pumps operating.

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ARKANSAS - UNIT 2 2-5 Amenchment No. 9,34,6,4M,MS, i

3/4.3 INSTRUMENTATION 3/4.3 1 REACTOR PROTECTIVE INSTRUMEhTATION LIMITING CONDITION FOR OPERATION 3.3.1.1 As a minimum, the reactor protective instrumentation channels and bypasses of Table 3.3-1 shall be OPERABLE-e44-44890N45-T!""! ;; ch:2 i:;

T:51: 3.3 2.

APPLICABILITY: As shown in Table 3.3-1.

ACTIONI As shown in Table 3.3-1.

SURVEILLANCE REQUIREMENTS l

4.3.1.1.1 Each reactor protective instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CKANNEL CALIBRATION and CHANNEL FVNCTIONAL TEST operations for the MODES and at the frequencies shown in Table 4.3-1.

4.3.1.1.2 The logic for the bypasses shall be demonstrated OPERABLE prior to each reactor startup unless perforned during the preceding 92 days. The

_ total bypass function shall be demonstrated OPERA 3LE at least once per-18 months during CHANNEL CALIBRATION testing of each channel affected by bypass operation.

4.3.1.1.3 The REACTOR TRIP SYSTEM RESPONSE TIME of each reactor trip function shall be demonstrated to be within its lindt at least once per 18 months. Neutron detectors are examet from reasonne time testina.

Each test l

shall include at least one channel per function such that all channels are tested at least once every N times 18 months where N is the total number of redundant channels in a specific reactor trip function as shown in the "Tutal No. of channels" column of Table 3.3-1.

4.3.1.1.4 The Core Protection calculator System shall be determined OPERABLE at least orte per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> by verifying that less than three auto restarts have occursed on each calculator during the past 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

4.3.1.1.5 The affected Core Protection calculator channel shall be subjected to a CHANNEL PUNCTIONAL TEST to verify OPERABILITY within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of receipt of a valid CPC Cabinet High Temperature alarm.

ARKANSAS - UNIT 2 3/4 3-1 Amendment No. 44,4M,MS, -

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INSTRUMENTATION 3/4.3.2 ENGINEERED SAFETY TEATURE ACTUATION SYSTEM INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.2.1 The Engineered Safety Feature Actuation System (ESTAS) instrumentation channels and bypasses shown in Table 3.3-3 shall be OPERAPLE with their trip setpoints set consistent with the values shown in the Trap Satpoint column of Table 3.3-4 : d with P.rtr0"!: TIM : :: :h:un in T b1: 2.3 5.

APPLICABILITY: As shown in Table 3.3-3.

ACTION:

a.

With an ESFAS instrumentation channel trip setpoint less l,

conservative than the value shown in the Allowable Values column of Table 3.3-4, declare the channel inoperable and apply the applicable ACTION requirement of Table 3.3-3 until the channel is i

restored to OPERABLE status with the trip setpoint adjusted consistent with the Trip Setpoint value, b.

With an ESFAS instrumentation channel inoperable, take the ACTION l

shown in Table 3.3-3.

SURVEILLANCE REQUIREMENTS 4.3.2.1.1 Each ESTAS instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL CALIBRATION and CHANNEL FUNCTIONAL TEST operations for the MODES and at the frequencies shown in Table 4.3-2.

4.3.2.1.2 The logic for the bypasses shall be demonstrated OPERABLE during the at power CHANNEL FUNCTIONAL TEST of channels af fected by bypass operation.

The total bypass function shall be demonstrated OPERABLE at least once per 18 months during CHANNEL CALIBRATION testing of each channel affected by bypass operation.

4.3.2.1.3 The ENGINEERED SAFETY TEATURES RESPONSE TIME of each ESTAS function shall be demonstrated to be within the limit at least once per 18 months.

Each test shall include at lemet one enannel per function such that all channels are tested at least once every N times 18 months where N is the total number of redundant channels it. a specific ESTAS function as shown in the " Total No. of Channels" Column of Table 3.3-3.

ARKANSAS - UNIT 2 3/4 3-10 Amendment No.

TABLE 3.3-4 (Continued)

ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION TRIP VALUES ALLOWABLE EUNCTIONAL UNIT TRIP VALUE VALUES 4.

MAIN STEAM AND FEEDWATER ISOLATION (MSIS) a.

Manual (Trip Buttons)

Not Applicable Not Applicable b.

Steam Generator Pre",sure - Low 2 7 g54 psia (2) 2 699.572^ 512 psia (2) l S.

CONTAINMENT COOLING (CCAS) a.

Manual (Trip Buttons)

Not Applicable Not applicable b.

Containment Pressure - High s 18.3 psia s 18.490 psia c.

Pressurizer Pressure - Low 2 1717.4 psia (1) 2 1686.3 psia (1) 6.

RECIRCUIATION (RAS) a.

Manual (Trip Buttons)

Not Applicable Not Applicable b.

Refueling Water Tank - Low 54,400 i 2,370 gallons between 51,050 and 58,600 (equivalent to 6.0 i 0.5%

gallons (equivalent to indicated level) between 5.111% and 6.889%

indicated level) 7.

LOSS OF POWER a.

4.16 kv Deergency Bus Undervoltage (Loss of Voltage) 3120 volts (4) 3120 volts (4) b.

460 volt Deergency Bus Undervoltage 423 i 2.0 volts 423 i 4.0 volts (Degraded Voltage) with an 8.0 i O.5 with an 8.0 1 0.8 second time delay second time delay ARKANSAS - UNIT 2 3/4 3-17 Anemnt No. 34,4N,444,444, L

=....

TABLE 3.3-4 (Continued)

ENGINEERED SAFETY FEATURE ACTUATION SYSTD1 INSTRUMENTATION TRIP VALUES ALLOWABLE FUNCTIONAL UNIT TRIP VALUE VALUES I

8.

EMERGENCY FEEIAtATER (EFAS) a.

Manual (Trip Buttons)

Not Applicable Not Applicable b.

Steam Generator (A&B) Level-Low 2 23% (3) 2 22.111% (3) c.

Steam Generator AP-High (SG-A > SG-B) s 90 psi s 99.344 psi d.

Steam Generator AP-High (SC-B > SG-A) s 90 psi s 99.344 psi e.

Steam Generator (A&B) Pressure - Low 2 7 g R psia (2) 2 699.6439,444 psia (2) l (1)

Value may be decreased manually, to a minimum of 2100 psia, during a planned reduction in pressurizer pressure, provided the margin between the pressurizer pressure and this value is maintained at 5 200 psis the setpoint shall be increased automatically as pressurizer pressure is increased until the trip set-point is reached. Trip may be manually bypassed below 400 psias bypass shall be automatically removed whenever pressurizer pressure is 2 500 psia.

(2)

Value may be decreased manually during a planned reduction in steam generator pressure, provided the margin between the steam generator pressure and this value is maintained at s 200 psis the se+ point shall be increased automatically as steam generator pressure is increased until the trip setpoint is reached.

(3)

% of the distance between steam generator upper and lower level instrument nozzles.

(4)

Inverse time relay set value, not a trip value. The zero voltage trip will occur in 0.75 i 0.075 seconds.

ARKANSAS - UNIT 2 3/4 3-18 Amendisert No.9,44,M,

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ARKANSAS - UNIT 2 3/4 3-20 Amendment No. GG,4-M,

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II IIIIIIilIilIIIIIIIiliIIIIII REGON OF UNACCEPTABLE OPERATON I!

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CONTAINMENT INTERNAL PRESSURE vs.

CONTAImfENT AVERAGE AIR TEMPERATURE FIGURE 3.6-1 NOTE:

Instrument Error is not Included on curve ARKANSAS - UNIT 2 3/4 6 ~1 Amendment No. 9,44,MG,M 6,

3/4.3 INSTRUMENTATION aASEs 3/4.3.1 and 3/4.3.2 PROTECTIVE AND ENGINEERED SAFETY FEATURES (ESF)

INSTRUMENTATION The OPERABILITY of the protective and ESF instrumentation systems and bypasses ensure that 1) the associated ESF action and/or reactor trip will be initiated when the parameter monitored by each channel or combination thereof reaches its setpoint, 2) the specified coincidence logic is maintained, 3) suf ficient redundancy is maintained to permit a channel to be out of service for testing or maintenance, and 4) sufficient system functional capability is available for protective and ESF purposes from diverse parameterr..

The OPERABILITY of these systems is required to provide the overall reliability, redundancy and diversity assumed available in the facility design for the protection and mitigation of accident and transient conditions. The integrated operation of each of these systems is consistent with the assumptions used in the accident analyses.

The surveillance requirements specified for these systeam ensure that the overall system functional capability is maintained comparable to the original design standards.

The periodic surveillance tests performed at the minimum frequencies are sufficient to demonstrate this capability. The triannual channel functional testing frequency is to be performed on a STAGGERED TEST BASIS.

The measurement of response time at the specified frequencies provides assurance that the protective and ESF action function associated with each channel is completed within the time limit assumed in the accident analyses.

The RPS and ESFAS response tim Ltab_1.es have been re b_ gated to the Safety l

Analysis Report (SAR).

No credit was taken in the analyses for those channels l

with response times indicated as not applicable.

Response time may be demonatrated by any series of sequential, overlapping or total channel test measurements provided that such testa demonstrate the total channel response time as defined.

Sensor response l

time verification may be demonstrated by either 1) in place, onsite or offsite test measurements or 2) utilizing replacement sensors with certified response times.

OTO ::: pen;; tim :. -de fined 2: the t4 =: ints: val :: quired f : the nTO cutput t schiev: 52.2S cf-4t: tet:1 chang: when subjected t: : tep change in OTO t;;p ::ture.

The nTO :::penee-bic: f: th: 00 : P::tection Calculab+e Gyeter (CPCS) i; expre;;;d :: :n effective tim: c nstant.

ro: het leg temperature;, th: c f-feetive-time-eenetent fe: : giver CPC channel is defined

the mean tim: : ns t-an t f: everaged pair: cf het leg "TO kaput: t; th channel.

Thi; 10 den; b : u:: the-CPCC utili::: the mean het leg temp :sture in it: :1 ulation:.

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ARKANSAS - UNIT 2 B 3/4 3-1 Amendment No. M, M,M 4, l

ATTACHMENT 1 DISCUSSION OF MAIN STEAM LINE BREAK ANALYZES 1

Attachment I ts 2CAN099703 Page1of65 ATTACHMENTI DISCUSSION OF MAIN STEAM LINE BREAK ANALYZES A lower low steam generator pressure setpoint has an impact on the following analyses:

SAR Event Description Section 6.2.1 Containment Functional Design - Main Steam Line Breaks 15.1.10 Excess Heat Removal Due to Secondary System Malfunction - Excess Heat Removal Due to Main Steam System Valve Malfunction 15.1.14 Major Secondary System Pipe Breaks with or without a Concurrent Loss of AC Power - Main Steam Line Break 15.1.14 Major Secondt.ry System I>ipe Breaks with or without a Concurrent Loss of AC Power - Feedwater Line Break The following sections will discuss the impacts of a lower low steam generator pressure setpoint on each of these analyses.

CONTAINMENT FUNCTIONAL DESIGN - MAIN STEAM LINE BREAKS A lower steam generator pressure setpoint will result in c. slightly longer delay prior to receiving a i

reactor trip and Main Steam Isolation Signal (MSIS) following a steam line break. This longer time will result in additional feedwater addition to the affected steam generator and delay the isolation of the unaffected steam generator. An increase in the mass and energy release to the containment building are anticipated as a result for main steam line breaks postulated within the containment building. The mass and energy release data for ANO-2 has not been regenerated since the original SAR analyses. As a result, an extensive effort was undertaken to update the analysis modelinput decks and use more recent versions of the analysis methods.

To determine the effects of a lower MSIS and Reactor Protection System (RPS) low steam generator pressure setpoint, a series of various postulated steam line ruptures from initial power levels consistent with those presented in the SAR were evaluated. At each power level, mass and energy releases were computed for the break size which resulted in no moisture cariyover for the given set of conditions. The no moisture carryover case produces the peak temperature and pressure parameters inside containment for a given power level. The following power levels and break sizes were considered:

6.19 ft steam line rupture at 102% power level, 2

6.19 ft steam line rupture at 98.4% power level.

2 e

5.26 ft steam line rupture at 75% power level.

2 e

4.33 ft steam line rupture at 50% power level.

2 3.09 ft steam line rupture at 25% power level.

2 1.547 ft steam line rupture at 0% power level.

2

Attachment I to 2CAN099703 Page 2 of 65 The MSIS and RPS low steam generator pressure setpoints assumed in this analysis were 655 psia for the 102% power case and 620 psia for all of the other power levels / break sizes. Due to the quick response time at 102% power (within 2 seconds the steam generator pressure reaches the 655 psia setpoint), instrument uncertainties were assumed based on abnormal containment conditions only; however, due to the longer response times at the lower power levels instrument uncertainties which account for accident conditions inside contentment were considered. The associated-Technical Speci8 cation limit with the above analysis assumptions, considering abnormal unceitainties on the 655 psia assumption and accident uncertainties on the 620 psia assumption,is 712 psia.

Consistent with the limiting event determined in the SAR, it is assumed that offsite power is available for the containment response analysis of the main steam pipe ruptures. This condition results in the greatest amount of heat transfer from the Reactor Coolant System (RCS) to the steam generator and, consequently, maximizes the mass and energy release to the containment.

The computer codes used for the analyses were the same used for the original Main Steam Line Break (MSLB) containment peak pressure analysis, however, the current revision of the codes were used. The RELAP5 MOD 3.1 code was used to generate the foodwater flow /enthalpy data and the SGN-RI code was used to determine the blowdown mass and energy for use in the COPATTA containment code. The feedwater input to the SGN-III code and the blowdown mass and energy release data inputs to the COPATTA code were generated by ABB-CE. Bechtel performed the COPATTA calculations. GOTHIC was used to screen some of the blowdown data being generated, with COPATTA runs being performed for the limiting cases.

GOTHIC is a general purpose thermal-hydraulics computer program for the analysis of containment and containment sub-compartment response to high energy line breaks.

The application of GOTHIC in this effort has been to aid in confirming the limiting break size and power level, and determining the limiting single failure. This screening effort has been confirmed by a review of the blowdown data, insights gained from the evaluations currently presented in the SAR, and confirmatory COPATTA analyses performed for this effort.

Feedwater flow is automatically terminated by closure of the main feedwater isolation valves (21.4 second response time) and back-up main feedwater isolation valves (16.4 second response time), and by tripping the main feedwater, heater drain, and condensate pumps with MSIS signals.

The main steam line isolation valve (MSIV) response time assumed in the analysis is 3.9 seconds.

Isolation of the MSIVs is also initiated with an MSIS signal. A low steam generator pressure signal based on 655 paia and 620 psia for the respective events as indicated above is assumed to initiate the MSIS signal.

The feedwater flow rate to the ruptured steam generator was cadated using RELAP5 MOD 3.1 for a series of active component single failures.

These feedwater flow rates were then ivorporated into SGN-III. The results of this parametric study accounting for single failures in the secondary system and containment systems established the limiting single failure. This study determined that the limiting single failure was a temporary loss of a vital bus due in a failure of the fast transfer mechanisms. This failure resulted in the delay of a containment fan cooler start, of one containment spray train start, and of the back up main feedwater isolation valves (MFIVs) closure until startup of the Emergency Diesel Generators (EDGs). Although credit could have

^

u

Attachment I to 2CAN099703 Page 3 of 65 been taken for closure of the main feedwater regulating valves, these valves were conservatively assumed to remain open.

Due to the use of different MSIS and RPS low steam generator pressure setpoints for various power levels, verification of the bounding power level was undertaken. This power level parametric study evaluates the competing effects ofinitial steam generator secondary inventory, core power and RCS temperatures, the break size required to generate a pure steam blowdown, low steam generator pressure setpoints, and feedwater flow rates and duraticn for different power levels.

Containment heat sink data consistent with the data presented in the SAR Tables 6.2-9 and 6.2 10 were assumed in this analysis. The heat sinks in Table 6.2 9 were simplified to the list in Table I for this analysis and the information in Table 6.2 10 was updated to the information in Table 2.

Cooler performance data consistent with vendor information provided in Table 3 was assumed in this analysis. This data reflects the anticipated performance of a train of coolers. Performance for a train of containment coolers is conservatively based on having only one fan in the train operable with at least 1250 gpm service water flow. The spray efficiency presented in SAR Figure 6.2-1 l

was also used in this analysis. Additional containment heat removal system assumptions and start times for the bus fast transfer failure limiting single failure case are presented in Table 4.

Conclusions The results of the various power level cases have been presented in Table 5.

COPATTA

. calculations were not performed on all of the cases based on a resiew of the blowdown data, screening calculations with GOTHIC, and the prior analysis results indicating the three cases

=====M were the top three Mass and energy release information for the limiting case, the 2770 MWt - 100% break area condition, is contained in Table 6.

The containment peak pressure analysis was completed using the COPATTA code and results of the limiting mass and energy blowdown data for the case where a temporary loss of a vital bus occurs due to a failure of the fast transfer mechanisms. The peak containment conditions were determined to be 53.0 psig and 423 'F (assuming initial containment conditions of 120 *F, 53 %

relative humidity, and 14.7 psia) which is below the original LOCA peak pressure analysis value of 53,4 psig and below the current MSLB peak pressure of 53.3 psig and peak temperature of 426

'F.

After determining the containment peak pressure limiting case, a set of initial containment conditions were established for initial containment pressure, temperature, and relative humidity.

This analysis used the same inputs and assumptions as those established for the determination of the MSLB peak containment pressure analysis except for the containment initial conditions.

Initial containment conditions identified in Table 7 were used in this assessment to ensure that the containment peak pressure is less than 54 psig.

Some of these initial containment conditions are more restrictive than the current Technical Specification limits, others are more relaxed. The limiting set of initial conditions defined in Table 7 is a combination oflimits established by this analysis effort and some established by the

Attachment I to 2CAN099703 Page 4 of 65 large break loss of coolant accident (LBLOCA) peak containment pressure analysis. A discussion of the proposed Technical Specification curve (Figure 3.61) is presented later in this Attachment.

Subsequent to the determination of the MSLB peak containment pressure limiting case (2770 MWt-6.19 A bus fast transfer failure case), an error was discovered in the mass and energy 2

blowdown data. The MSLB maximum pipe break area used in the above analysis (6.19 ft') was slightly less than the maximum possible as installed area givec. a guillotine break in the main steam line (6.357 ft ). As a result, new blowdown data was generated for the 102% (6.357 ft') and 2

98.4 % (6.25 ft') power levels considering the limiting single failure. The small inen ase in blowdown data anticipated by tids change was offset by taking credit for at least 10% of the steam generator tubes being plugged. The ANO-2 steam generators are currently ~13.6%

plugged.

Before reanalyzing the peak containment pressure using the new blowdown data, changes to the COPATTA containment code input data were undertaken. The changes included decreasing the containment air cooler performance data to account for a service water temperature of 120 'F, adjusting the containment liner metal heat sink data to account for the additional me:al stiffeners attached to the liner plate, and decreasing the start of the containment spray actuation. The heat sink change is simply a more explicit application of these heat sinks as presented in Table 6.2-9 versus the more simplified set presented in Table 1. Both sets of heat sink data are conservative with respect to the actual heat sinks. The change in the spray response time removes some of the conservatism between the analysis assumption and the actual system capabilities.

In this subsequent analysis, the first train was actuated 38.6 seconds after the 11 psig setpoint is reached and the second train is actuated 53.6 seconds after the 6 psig setpoint is reached. The quicker response times compared to those reflected in Table 4 are based on actual system capabilities.

The actuation of the second spray train based on the lower high containment pressure setpoint is consistent with the conservative timing of when the fast transfer failure would occur. Bus fast transfer would be initiated some time after the high containment pressure setpoint of 6 psig is reached due to a reactor trip sign I and Safety Injection Actuation Signal (SIAS) which are generated on this setpoint. The SIAS signal will start the EDG at this time which is integral to the spray response time.

The resulting peak containment pressure was 52.3 psig which is slightly less than the previous analysis value of 53.0 psig. The results from the above analysis with the data consistent with the 2

6.19 ft break area remain bounding.

EXCESS HEAT REMOVAL DUE TO SECONDARY SYSTEM MALFUNCTION -

EXCESS HEAT REMOVAL DUE TO MAIN STEAM SYSTEM VALVE MALFUNCTION Excess heat removal due to secondary system malfunction can occur as a result of feedwater system or main steam system valve malfunctions. Excess heat removal causes a decrease in the temperature of the reactor coolant, an increase in reactor power due to the negative moderator temperature coefficient and a decrease in the RCS and steam generator pressures. Detection of these conditions is accomplished by alarms due to low RCS and steam generator pressures and high reactor power.

_--_)

i i

l Attachment I to 2CAN099703 i

Page 5 of 65 i

Excess heat removal due to main steam system valve malfunctions may be caused by:

l a)

Rapid opening of the turbine admission valves.

j b)-

Opening of one of the steam dump and bypass system valves at power due to a -

control system failure.

i c)

Opening of one of the steam dump and bypass system valves at hot standby conditions due to a control system failure.

d)

Inadvertent opening of an atmospheric dump valve (ADV).

l The excess heat removal incident due to the opening of the ADVs has been determined to be the 5

i most severe incident. Lowering the MSIS low steam generator pressure setpoint from 678 psia to 620 psia will not affect this event with respect to the time of plant trip. Plant trip is initiated in this event based on'a low steam generator level condition. Lowering the low steam generator i

pressure trip setpoint will delay the time at which an MSIS signal is generated. An MSIS signal is credited as isolating the unaffected steam generator. For this event it was assumed that one of the j

ADVs upstrwt of the MSIVs inadvertently opened and operator action was required to isolate

[

the affected steam generator (based on the current plant design this event is no longer credible; however no credit has been taken for this change). A longer delay in isolating the unaffected steam generator will result in a slightly larger steam generator mass release than that presented in i

the SAR. Less than a 10% increase in the amount of mass release indicated in the SAR for this event is conservatively estimated. As a result, the total mass released under these conditions are i

well within those considered later for the MSLB Based on the bounding nature of the MSLB l

release, the results of the MSLB event can be used to bound this event.

Conclusions l

The changes being proposed by this package do not affect the results of this event with respect to i

the timing of reactor trip and thereby do not affect the conclusion with respect to the minimum i

DNBR, maximum local power density, and peak primary and secondary system pressures.- A j-steam dump and bypass system malfunction may cause a reactor trip but no core damage results since the minimum DNBR and maximum local power density remain within acceptance criteria.

The radioactivity release for this event is bounded by the results of the MSLB event which are well within 10CFR100 limits.

i j'

MAJOR SECONDARY SYSTEM PIPE BREAKS WITH OR WITHOUT A i-CONCURRENT LOSS OF AC POWER - MAIN STEAM LINE BREAK 1

i A decrease in the steam generator low pressure MSIS and RPS setpoint will result in a delay in i

reactor trip and isolation of the feedwater flow to both steam generators and steam flow from the i

unaffected. sten n generktor following a MSLB. The additional feedwater flow and delayed j

- isolation of steam flow from the unaffected steam generator following a MSLB will result in a small amount of additional overcooling. The curr-nt Cycle 13 analysis already accounts for a low

1 Attachment I ts 2CAN099703 Page 6 of 65 steam generator pressure setpoint of 620 psia. The following is a summary of the Cycle 13 analysis which includes the new setpoint and various other conservative assumptions.

The no moisture carryover steam line break events were reanalyzed to account for a 10 %

reduction in the RCS design flow, a small increase in feedwater flow, a lower low steam generator pressure setpoint, and address Cycle 13 physics data. CENTS was used to model the NSSS response, RCP coastdown and. natural circulation, RELAPS was used to model the feedwater system response for the hot full power (HFP or full load) cases, HRISE was used to calculate thermal margin on DNBR, and ROCS /HERMITE were used to assess reactivity feedback and Peaking.

The analytical basis for the HFP and hot zero power (HZP) simulations are discussed below.

A.

A double-ended guillotine break (6.357 ft ) causes the greatest cooldown of the RCS and 2

the most severe degradation of shutdown margin.

B.

A break inside the containment building, upstream of the MSIVs and flow measuring venturis causes a non-isolable condition in the affected steam generator.

C.

A SIAS is actuated when the pressurizer pressure drops below 1400 psia. Time delays associated with the safety injection pump acceleration and valve opening are taken into

. account. A 40 second HPSI response time was assumed to account for these delays.

Additionally, the event was initiated from the highest pressure allowed by the technical specifications to delay the effect of the safety injection boron addition.

D.

The cooldown of the RCS is terminated when the affected steam generator blows dry. As the coolant temperatures begin increasing, positive reactivity insertion from moderator reactivity feedback decreases. The decrease in moderator reactivity combined with the negative reactivity inserted via boron injection cause the total reactivity to become more negative.

E.

CENTS is used to model the RCP pump coast down on a loss of offsite power. The CPC low DNBR (based on pump speed) trip is credited in this analysis following a loss of offsite power. A CPC low DNBR trip setpoint based on 96.5% of RCP speed with a 1.0 second response time are assumed.

F.

A low steam generator pressure reactor trip setpoint of 620 psia was assumed with a 1.3 second response time.

G.

MSIS is actuated on a low steam generator pressure setpoint of 620 psia. The MSIVs, MFIVs and Back-up MFIVs all receive an MSIS signal to close. A response time of 4.3 seconds was assumed for the MSIVs. The MFIVs and Back-up MFIVs were assumed to close in 36.4 seconds and 31.8 seconds with a loss of offsite power, and 21.4 seconds and 16.8 seconds with offsite power available, respectively.

H.

The HERMITE code was used to calculate the reactivity for the post-trip return to power portion of the analysis. This was done since the HERMITE code, which is a three-to 2CAN099703

- Page 6 of 65 steam generator pressure setpoint of 620 psia. The following is a summary of the Cycle 13 analysis which includes the new setpoint and various other conservative assumptions.

J The no moisture carryover steam line break events were reanalyzed to account for a 10 %

reduction in the RCS design flow, a small increase in feedwater flow, a lower low steam generator preasure setpoint, and address Cycle 13 physics data. CENTS was used to model the NSSS regonse, RCP coastdown and natural circulation, RELAP5 was used to model the feedwater system response for the hot full power (HFP or full load) cases, HRISE was used to calculate thermal margin on DNBR, and ROCS /HERMITE were used to assess reactivity feedback and Peaking.

The analytical basis for the HFP and hot zero power (HZP) simulations are discussed below.

l A.

A double-ended guillotine break (6.357 ff) causes the greatest cooldown of the RCS and i

the most severe degradation of shutdown margin.

B.

A break inside the containment building, upstream of the MSIVs and flow measuring venturis causes a non-isolable condition in the affected steam generator.

C.

A SIAS is actuated when the pressurizer pressure drops below 1400 psia. Time delays associated with the safety injection pump acceleration and valve opening are taken into account. A 40 second HPSI response time was assumed to account for these delays.

Additionally, the event was initiated from the highest pressure allowed by the technical specifications to delay the effect of the safety injection boron addition.

D.

The cooldown of the RCS is terminated when the affected steam generator blows dry. As the coolant temperatures begin increasing, positive reactivity insertion from moderator reactivity feedback decreases. The decrease in moderator reactivity combined with the negative reactivity inserted via boron injection cause the total reactivity to become more negative.

E.

CENTS is used to model the RCP pump coast down on a loss of offsite power. The CPC low DNBR (based on pump speed) trip is credited in this analysis following a loss of offsite power. A CPC low DNBR trip setpoint based on %.5% of RCP speed with a 1.0 second response time are assumed.

F.

A low steam generator pressure reactor trip setpoint of 620 psia was assumed with a 1.3 second response time.

G.

MSIS is actuated on a low steam generator pressure _ setpoint of 620 psia. The MSIVs, MFIVs and Back-up MFIVs all receive an MSIS signal to close. A response time of 4.3 seconds was assumed for the MSIVs. The MFIVs and Back-up MFIVs were assumed to close in 36.4 seconds and 31.8 seconds with a loss of offsite power, and 21.4 seconds and 16.8 seconds with offhite power available, respectively.

H.

The HERMITE code was used to calculate the reactivity for the post-trip return to power portion of the analysis. This was done since the HERMITE code, which is a three-

Attachment I to 2CAN099703 i

Page 7 of 65 dimensional coupled neutronics-open channel thermal hydraulics code can more accurately model the effects of moderator temperature feedback on the. power distribution and i

reactivity for the critical configuration existing during the return to power.

The l

HERMITE results used in the ANO-2 analysis were actually obtained from a parametnc study performed for Calvert Cliffs Unit 1 Cycle 7. ANO-2 specific ROCS calculations l

were used to confirm the applicability of these parametric results to ANO-2.

L l

1.

Three-dimensional power distribution peaks (Fq) were determined with the above l

mentioned ROCS and HERMITE evaluations.

Axial profiles consister;t with these conservative power distribution peaks were utilized in the analysis.

3' J.

The power produced by the decay of the initial condition delayed neutron precursors and by nominal decay power is distributed according to the nominal power distribution.

I K.

The thermal margin on DNBR in the re.ctor core was simulated using the HRISE l

computer program. RCS conditions from CENTS (RCS temperature, pressure, flow, and power) are used in the HRISE thermal margin calculations.

The conservative assumptions included in the HZP and HFP simulations are discussed below.

The MTC assumed in the analysis corresponds to the most negative value, This negative MTC results in the greatest positive reactivity addition during the RCS cooldown caused by the steam line break.

Since the coefficient of reactivity associated with moderator feedback varies i

significantly over the range of moderator density covered in the analysis, a curve of reactivity insertion versus moderator density rather than a single value of MTC is assumed in the analysis.

The moderator cooldown curve used in the analysis (Figure 1) was conservatively calculated assuming that on reactor trip, the highest worth control element assembly is stuck in the fully

• withdrawn position. The effect of uneven temperature distribution on the moderator reactivity is accounted for by assuming that the moderator reactivity is a function of the lowest cold leg 4

temperature.

- For conservatism, the full steam generator heat transfer surface area is assumed to always be i

covered by the 2-phase level until a steam generator becomes essentially empty.

The reactivity effect associated with fuel temperature decrease is based on the most negative Fuel Temperature Coefficient (FTC). Figure 2 represents the FTC curve used in the analysis. This FfC, in conjunction with the decreasing fuel temperatures, causes the greatest positive reactivity insertion during the steam line break event. The delayed neutron fraction assumed is the maximum value including uncertainties for end-of-life conditions (total delayed neutron fraction, j

p, 0.005994). This too maximizes subcritical multiplication and thus increases the potential for l

return to power.

The minimum CEA worth assumed to be available for shutdown at the time of reactor trip at the maximum allowed power level is -7.5144 % Ap. For the HZP cases a shutdown CEA worth of-5.0 % Ap wpS used. The scram worths used are consistent with the moderator cooldown curve l

and stuck rod assumed in the analysis. The CEA reactivity addition curve of Figure 3 adjusted to l

a worth of 7.5144 was used in the HFP cases. The HZP cases assumed a CEA drop time l

l t

- - ~,

i i

Attachment I to 2CAN099703 l

Page 8 of 65 consistent with Figure 3 with the 0.6 second holding coil delay time; however, a more conservative nonnalized reactivity insertion versus CEA position for a M6 ASI curve was used.

l The EFW system is conservatively modeled to initiate early with both EFW pumps available, this

[

maximizes the potential cooling that could occur. System response times, flows and setpoints are l

assumed based on increasing the cooling potantial of the EFW system.

The analysis samuned that, for the loss of AC power cases one EDG failed to start, The failure of i

an EDG results in the failure of one HPSI pump and one of the main feedwater isolation valves to close (the faster closing back-up MFIVs were assumed to remain open). For the HFP case with 1

AC available, a bus fast transfer failure is the most limiting single failure as this failure is modeled as the failure of the back-up MFIVs and a HPSI pump. A fast transfer failure would only result in the delayed actuation of the back-up MFIV and HPSI pump. These components would be j

actuated once the EDG has started. Therefore, the modeling of the fast transfer failure is j

conservative, This conservative modeling of a fast transfer failure is slightly more limiting than the single failure of a main feedwater pump to trip, which was determined to be more limiting in j

the Cycle 12 analysis. A single failure of a HPSI pump to start was assumed for the HZP case with AC available. The boration from the Safety Injection Tanks was not credited in this analysis.

The HFP feedwater addition to the steam generator assumed in this analysis is taken f! rom the Cycie 12 analysis which used a RELAPS model of the feedwater system. The steam generator i

pressure profiles and time of MSIS were veri 6ed to be consistent with respect to this analysis, thereby allowing the application of the feedwater data generated for Cycle 12. The HFP feedwater data for Cycle 12 was increased by 1% to account for a small expected increase in

[

feedwater flow due to modifications to the high pressure turbine. For the hot zero power (HZP or no load) cases, feedwater flow is modeled by matching the energy input by the core at the start

[

of the event.

The key parameters used for the post-trip steam line break analyses are listed in Table 8. Tables 9 through 12 present the sequence of events for the HFP and HZP steam line break cases with and without a concurrent loss of AC power. Figures 4 through 27 show the transient response for key parameters.

The results of this analysis indicate that the HFP cases remain suberitical through out the post trip event. The new maximum post trip reactivity values are -0,029 and -0.338 considering a loss of AC and offsite power available, respectively. The peak return to power and minimum DNBR values are 2.61% and 1.81, and 4.98% and 2.46 considering a loss of AC and offsite power available, respectively.

The HZP results of this analysis indicate a slight return to critical; however, this return to critical is bounded by the FSAR results; The new maximum post trip reactivity values are +0.252 and

+0.227 considering a' loss of AC and offsite power available, respectively. These values are bounded by the FSAR analysis results of +0.43 and +0.34.

The peak return to power and minimum DNBR values are 0.41% and 12.3, and 1.275% and 11.2 considering a loss of AC and offsite power available, respectively.

. - - _ _ _ to 2CAN099703 Page 9 of 65 As these results indicate acceptable DNBR values, no fuel failure is prMicted. The results of the steam line break analyses demonstrated that there was no calculated fuel failure, thus the coolable geometry is maintained.-

Offsite Release

- A lower low steam generator pressure setpoint as indicated above svill restdt in a delay in the isolation of the steam generators. This slight delay in isolation of the steam generators will result in some additional mass release to the environment thereby affecting the offsite dose. Two dose calculations were performed for verification purposes. The first dose calculation assumed a preaccident iodine spike by assuming an initial RCS iodine concentration of 60 Ci/gm dose equivalent I-131. A second dose calculation was performed assuming the MSLB creates an iodine spike in the primary system. This iodine spike'is modeled as an increase in the primary system iodine release rate. The increase in primary coolant iodine release rate is assumed to be 500 times the initial release rate that corresponds to a 1.0 pCi/gm dose equivalent I-131 equilibrium concentration.

A conservative decontamination factor of 100 was assumed for the iodine concentration released

-in the steam from the intact steam generator liquid. The secondary side initial steady state radiological concentration was assumed to be 0.10 pCi/gm dose equivalent I-131. The primary side specific activity was assumed to be 60.0 Ci/gm dose equivalent I-131 for the preaccident case. An initial primary system release rate that results in an initial concentration of 1.0 pCi/gm dose equivalent 1-131 was based on make-up flow of 44 gpm, for the accident induced iodine spike. A primary side specific activity equal to 100/E pCi/gm was assumed for the non-iodine

' concentration in both of the calculations.

To detennine the radioactive release for the main steam line break accident, HZP mass releases were used with decay heat considerations based on full power. A HZP case similar to the one presented above was used in this assessment. Like the above case, the blowdown data is based on a MSLB inside containment upstream of the flow limiting venturi. This blowdown ' formation m

was used assuming the break was located outside containment but upstream of the main steam isolation valves. This approach is considered conservative as no credit is taken for the flow funiting venturi. A break in the main steam line outside containment and upstream of the main steam line isolation valves is assumed to result in the maximum radioactive release for this accident.

Cooldown of the plant following the accident is conservatively assumed to take place using the atmospheric dump valves. This results in additional release due to the venting of steam directly to the atmosphere. Also, it is assumed that the iodine transported through the assumed primary-to-secondary leak in the ruptured steam generator is discharged directly to atmosphere. A 0.5 gpm primary-to-secondary leak is assumed in the ruptured steam generator and a 0.5 gpm primary-to-secondary leak is assumed in the intact steam generator.

Since it is assumed that all the iodine contained in the damaged steam generator exits through the rupture, the iodine release calculated for this accident is conservative. No credit is taken for decontamination in the damaged unit.

Attachment I ts 2CAN099703 Page 10 of 65 These two dose calculations are conservative with respect to the licensing basis analysis. The licensing basis analysis used the radiological information presented in Section 15.1.0 of the SAR.

Only a dose calculation was presented based on the initial primary and secondary concentrations without assuming a preaccident-iodine spike or an induced iodine spike.

Given this, the preaccident iodine spike case is most consistent with the methods used for the dose calculations presented in the SAR except:

a)

A decontamination factor of 100 was assumed in this assessment. This is more conservative than the value of 400 presented in Section 15.1.0.5.1 which was assumed for the iodine concentration released in the steam from the intact steam generatorliquid.

b)

The secondary side initial steady state radiological concentration was assumed to be 0.10 Ci/gm dose equivalent I-131, and the primary side initial specific activity was assumed to be 60 Ci/gm dose equivalent I-131.

c)

The isotope physical data presented in SAR rable 15.1.0-3 was used in the SAR analysis. The iodine physical data presented in Table 13 was assumed in this analysis.

Due to the assumption in t!ss assessment that the primary side specific activity was 3

assumed to be 60.0 pCi/gm dose equivalent I-131 (as noted above) and equal to 100/E pCi/gm, the rest of the information in the SAR table is not needed and is not presented on Table 13.

The noted exceptions above delineate conservative assumptions used in the preaccident iodine spike case with respect to the licensing basis analysis requirements.

The resulting 2-hour and 8-hour thyroid dose for both cases is less than 10.0 rem and 5.0 rem, respectively. The resulting 2-hour and 8-hour whole body dose for both cases is less than 0.03 rem and 0.01 rem, respectively.

These results are well within 10CFR100 limits and are considered acceptable.

Maior Secondary System Pine Breaks with or without a Concurrent Loss of AC Power -

Feedwater Line Break Isolation of the unaffected steam generator following a feedwater line break is accomplished by an MSIS signal. Reducing the low steam generator low pressure setpoint will delay this function.

To ensure this had a' minimal impact on the results, the Cycle 13 feedwater line break analyis assumed a MSIS low steam generator pressure setpoint of 620 psia.

The feedwater line break accident analysis with a loss of AC power was analyzed using CENTS to account for Cycle 13 physics data. This analysis was performed essentially consistent with the analyses described in the SAR assuming a loss of AC and using the inputs from Table 14. The analytical bases are discussed below.

A.

The feedwater line break analyzed was assumed to occur during full power operation (2900 MWt) with a loss of offsite power at the time trip breakers open. With a loss of

Attachment I ts 2CAN099703 Page 11 of 65 offsite power the turbine stop valves are assumed to close, the reactor coolant pumps begin to coast down, and the pressurizer control systems are lost.

B.

A CEA insertion curve consistent with the CEA position versus time (including a 0.6 second holding coil delay time) of Figure 3 is used in this analysis; however, a more conservative normalized reactivity insertion versus CEA position for a +0.6 ASI curve was used. The minimum CEA worth assumed available for shutdown, with the most reactive CEA remaining in the fully withdrawn position, when the reactor is tripped is -

5.0% Ap.

C.

The Doppler curve assumed is consistent with the BOC curve in Figure 28 which already includes a 0.85 multiplier.

D.

The initial intact steam generator liquid inventory was assumed to be 168,700 lbm and 93,060 lbm was assumed for the affected unit. These masses were used to ensure the coincidence trip conditions described below.

E.

A low steam generator pressure trip does not occur until minutes after the high pressurizer pressure trip and low steam generator level trip conditions occur.

F.

Only flow from one EFW pump was credited to the steam generator with the intact feedwater line. Flow to this generator is based on a 36.3 second delay aRer a low steam generator pressure condition exists, which is 225 seconds after a low steam generator level condition occurs. This allows time for the EFW pumps to accelerate and flow to the affected steam generator to be isolated prior to crediting EFW flow to the intact steam generator.

G.

A MSIS low steam generator pressure setpoint of 620 psia was assumed with a 1.3 second response time. A 3 second MSIV stroke time (4.3 second response time) and 35 second EFW isolation valve stroke time (36.3 second response time) were also assumed.

H.

A conservatively smad vaice for the fuel gap heat transfer coefficient was a umed corre.ponding to BOL.

I.

The lid tolerance for the primary safety valves and secondary safety valves was assumed to be +3% of setpoint.

J.

Decay heat was maximized by assuming equilibrium core conditions.

K.

The Cycle 13 delayed neutron fraction (0.007252) and neutron lifetime (36x10 sec) were 4

assumed The conservative assumptions included in the feedwater line break simulation are discussed below.

The feedwater line break was assumed to occur during full power operation with concurrent loss of non-emergency AC power at the time of trip. This is limiting from the standpoint of potential

Attachment I to 2CAN099703 Page 12 of 65 RCS pressure increase, since this results in the maximum initial stored energy and minimum steam generatorinventory.

A new limiting break size was established by a parametric study as part of this effort. The limiting break size was revisited due to the use of CENTS versus CESEC. The new limiting break size has become that which is sized to pass all feedwater flow but not large enough to cause back flow from the ruptured steam generator. No back flow is modeled until aAer trip when the feedwater goes away. Feedwater is assumed to go to zero at the start of the event. The break area 2

-e y to pass all feedwater is assumed to be 0.24 R.

h steam generator heat transfer area is conservatively assumed to be fully available down to 19,000 lbm ofliquid in the steam generator at which point the area is ramped down to zero at 2000 lbm.

It is conservatively assumed that the blowdown of the affected steam generator is saturated water, when in reality the blowdown would change to "two phase discharge" aRer the water level dropped below the feedwater ring.

l The initial RCS pressure and initial steam generator inventories are selected such that the Low Steam Generator Water Level Trip on the intact steam generator and the High Pressurizer Pressure Trip occur simultaneously with the dryout of the affected steam generator. This results in the maximum peak RCS pressure aAer trip. A 1.3 second response time has been associated with the low steam generator level trip and a 0.9 second response time with the high pressurizer pressure trip. This difference in response time is reflected in the sequence of event.

The feedwater line break event was initiated at the conditions shown in Table 14. Table 15 presents the sequence of events for this transient. Figures 29 through 33 show the transient response of the key parameters. The results indicate that the reduction of the secondary heat sink and subsequent emptying of the affected steam generator cause the RCS pressure to *meresse to a maximum of 2730.1. psia.

Following reactor trip on high pressurizer pressure / low steam generator ("mtact) water level, the decay in core power and the action of the PSVs and MSSVs results in a reduction of the RCS and steam generator pressures. The RCS pressure continues to decrease until low steam generator pressure initiates the closure of the MSIVs and MFIVs. The MSIV closure terminates the blowdown of steam from the intact steam generator through the break thus causing the RCS to heat up once more. This heatup is terminated by the opening of the MSSVs and initiation of emergency feedwater to the intact steam generator.

The results of tis analysis indicate that the new peak RCS pressure is 2730.1 psia. 'The peak RCS pressure predicted by CENTS is less than the current peak of 2742 psia already in the SAR.

Part of this reduction in pressure is due to the use of CENTS versus CESEC. The peak RCS pressure is within the acceptance criteria of 110% of design pressure (2750 psia).

CONTAINMENTINITIAL CONDITIONS The containment initial conditions defined in Technical Specification Figure 3.6-1 is comprised of essentially three analysis efforts. The first effort is the large break LOCA 10CFR50.46 analysis

Attachment I to 2CAN099703 Page 13 of 65 which is based on a conservative minimum initial containment pressure and temperature. No changes are being proposed to this data point noted on the figure as 60 'F and 13.2 psia.

3 Containment design negative pressure differential with respect to the outside atmosphere of 5.0 psid is established by the lower right hand curve on Figure 3.6-1. All data points establishing the design negative pressure differential curve (125.7 'F and 13.2 psia,130 'F and 13.5 psia, and 140 'F and 14.4 psia) are not affected by the requested change. Only the upper portion of Figure 3.6-1 is being adjusted by this change package as a result of the new MSLB peak containment pressure analysis. The upper portion of this curve is established to ensure the peak containment pressure does not exceed 54 psig following a pos*.'ated MSLB or LOCA.

As indicated above, the allowable initial containment conditions were revisited as a result of the new MSLB analysis generated for the lower low steam generator pressure setpoint. The limiting MSLB case identified above (2770 MWt-6.19 ft' bus fast transfer failure case) was used to establish the new allowable initial conditions def:ned in Table 7, The acceptable initial containment conditions for a large break LOCA analysis are also presented in Table 7.

The LBLOCA analysis effort was conducted as part of the Amendment 171 effort and is noted in the SAR Section 6.2.1.3.3.4.2. The 'untial conditions assumed in this effort included those provided in Table 7.

Table 7 la used to compare the results of the latest ANO-2 MSLB and LOCA peak containment pressure analyses to identify the limiting initial containment pressure at a given initial containment humidity and temperature. As can be seen from the table, the lindting values are made from a combination of the MSLB and LOCA events.

The limiting values from Table 7 are incorporated into the new Figure 3.6-1.

Where the conditions for more than one of the analytical efforts cross, the limiting condition of the two are incorporated into the figure.

m e

Attachment I ts 2CAN099703 Page 14 of 65 Table i HEAT SINK GEOMETRIC DATA FOR THE MAIN STEAM LINE BREAK PEAK CONTAINMENT PRESSURE REANALYSIS TO JUSTIFY A LOWER MSIS AND RPS STEAM GENERATOR LOW PRESSURE SETPOINT Thickness Surface Area Heat Sink (in)

(sa. fl.)

1.

Containment Walls and Dome Coating (Type B)

.006 56,634 Carbon Steel Liner Plate

.25 Air

.12 Concrete 45.00 2.

Containment Walls and Dome Coating (Type C)

.009 20,300 Carbon Steel Liner Plate

.25 Air

.12 l

Concrete 45.00 3.

Refuel Canal Stainless Steel

.25 18,000 Air.12 Concrete 48.0 4.

Steel Floor Structures Coating (Type C)

.006 34,824 Carbon Steel

.25 5.

SteelFloor Structures Coating (Type C)

.006 44,700 Carbon Steel

.09375 6.

Concrete Floor Structures Coating (Type C)

.128 11,500 Concrete 13.152 7.

Base Slab and Sump Coating (Type C)

.128 9,300 Concrete 18.0 8.

Unlined Concrete Walls and Structures Concrete 24.0 42,584

Attachment I to 2CAN099703 Page 15 of 65 Table 1 (continued)

Thicknen Surface Area Heat Sink (in.)

(sa. fl.)

9.

Uninsulated Concrete Walls Coating (Type C)

.0655 13,116 Concrete 24.0 10.

Polar Crane Rail Support Steel Coating (Type D)

.006 8,542 Carbon Steel

.750 11.

Trolley Steel l

Coating (Type D)

.011 40,371 l

Canbon Steel

.1882 12.

Box Girders Coating (Type D)

.011 6,020 Carbon Steel

.375 13.

Elevator. Galvanized Flat Steel Plate Carbon Steel

.032 7,110 14.

MS Pipe and MS Pipe Restraints Coating (Type C)

.006 4,600 Carbon Steel

.625 15.

Spray Head and Hydrogen Recomb.

Stainless Steel

.12 2,101 16.

Cable Trays Carbon Steel

.0415 11,620 17.

Conduit Conduit

.125 4,541 18 Refueling Apparatus Stainless Steel

.375 2,075 19.

Heating and Vent Ducts Carbon Steel

.0806 22,690 20.

Safetyinjection Tanks Coating (Type C)

.006 3,796 Carbon Steel 1.835

Attachment i 13 2CAN099703 Page 16 of 65 Table 2 HEAT SINK THERMODYNAMIC DATA FOR THE MAIN STEAM LINE BREAK PEAK CONTAINMENT PRESSURE REANALYSIS TO JUSTIFY A LOWER MSIS AND RPS STEAM GENERATOR LOW PRESSURE SETPOINT MATERIAL PROPERTIES Specific Thermal Heat Conductivity Material (Btu /cu fi *F)

(Btu /hr-ft.*F)

Type C Coating (Phenoline 305 Topcoat 33 0.1 on Carbozine 11 Primer)

Carbon steel 54 25 Concrete 30 0.8 Stainless steel 54 10 Type B Coating (Carbozine 11 Primer) 30 0.9 Conduit (Zine Coated) 42 62 Type D Coating (Epoxy) 30 7.4 HEAT TRANSFER COEFFICIENTS Value Surface Sink surfaces exposed to containment Uchida Correlation atmosphere O

Sump liquid to containment atmosphere Containment sump and floor to sump liquid 0.4 Btu /hr-sq ft 'F Sink surfaces exposed to outside 2.0 Btu /hr-sq ft-F

Attachment I to 2CAN099703 Page 17 of 65 TABLE 3 CONTAINMENT AIR COOLER DUTY FOR THE MAIN STEAM LINE BREAK PEAK CONTAINMENT PRESSURE REANALYSIS TO JUSTIFY A LOWER MSIS AND RPS STEAM GENERATOR LOW PRESSURE SETPOINT 105 'F SERVICE WATER,1,250 GPM FLOW,30,000 ACFM Vapor Temocrature (*F)

Heat Transfer (x10' Btu /hr) 105 0

150.0 8.81 180.0 18.07 230.0 39.35 286.0 66.40 s

I

Attachment I to 2CAN099703 Page 18 of 65 TABLE 4 CONTAINMENT HEAT REMOVAL SYSTEMS PERFORMANCE FOR TIIE MAIN STEAM LINE BREAK PEAK CONTAINMENT PRESSURE REANALYSIS TO JUSTIFY A LOWER MSIS AND RPS STEAM GENERATOR LOW PRESSURE SETPOINT Containment Splay Water Source Refueling Water Tank Water Temperature, 'F 120 Initiating Pressure, psig 11 Flow Rate per Pump, gpm 2,000 l

Containment Air Coolers i

Initiating Pressure, psig 6

l Flow Rate (Air Side) per Unit, cfm 30,000 l

Service Water Flow Rate per Unit, gpm 1,250 Service Water Temperature, 'F 105 time (seconds)

Event 0.0 Postulated break occurs 1.55 Containment pressure reaches CCAS setpoint (6 psig) 3.2 Containment pressure reaches CSAS setpoint (11 psig) 29.65 First Train of containment cooler fans at full capacity 43.2 First Train of containment spray at rated flow 52.55 Second Train of containment cooler fans at full capacity 58.2 Second Train of containment spray at rated flow Note :

Containment Spray System and Containment Cooler start times varied with the various cases considered. These start times are those determined for the 2770 MWt - 100%

break area condition with offsite power available and a single failure of a vital electrical bus to fast transfer to offsite power. These start times are considered conservative based on the anticipated chronology of events:

Attachment I to 2CAN099703 Page 19 of65 TABLE 5 RESULTS OF MAIN STEAM LINE BREAK REANALYSIS TO JUSTIFY A LOWER MSIS AND RPS STEAM GENERATOR LOW PRESSURE SETPOINT BREAK BREAK MSIS TIME AT INT.

INT.

• PEAK TIME OF OF SIZE AREA SET END OF MASS ENERGY CNTMT PEAK 2

2815

(% OF (A )

POINT BLOW (Ibm x (Btu x 10') PRESSURE CNThff 2

MWt 6.19 A )

(psia)

DOWN 10')

(psig)

PRESSURE (seconds)

(wnnds) 102 100 6.19 655 90.0 2.062 2.471 54.0 58.4 98.4 100 6.19 620 90.0 2.091 2.505 54.0 58.4 75 85 5.26 620 118.0 2.158 2.583 50 70 4.33 620 146.8 2.177 2.604 25 50 3.10 620 216.2 2.378 2.842 0

25 1,55 620 221.6 2.577 3.092 50.6 191.6

• These peak containment pressures are based on initial containment conditions of 140 'F,7%

Relative Humidity, and 14.4 psia.

Attachment I ts 2CAN099703 Page 20 cf 65 Table 6 MAIN STEAM LINE BLOWDOWN DATA USED IN THE MAIN STEAM LINE BREAK PEAK CONTAINMENT PRESSURE REANALYSIS TO JUSTIFY A LOWER MSIS AND RPS STEAM GENERATOR LOW PRESSURE SETPOINT 2,770 MWt - 100 PERCENT BREAK AREA (6.19 SQ. FT.)

Time Mass Flow Enthalpy Time Mass Flow Enthalpy (sec.)

(Ibm /sec.)

(Btu /lbm)

(sec.)

(Ibm /sec.)

(Blu.%m) l 0

0 0

3.2 7775.68 1203.69 0.1 12840.8 1196.3 3.4 7619.96 1203.72 0.2 12553.I 11 %.93 3.6 7475.42 1203.74 0.3 12278.8 1197.51 3.8 7341.27 1203.75 0.4 12016.7 1198.04 4

7216.79 1203.74 0.5 11766 1198.53 4.2 7101.22 1203.72 0.6 11526 1198.99 4.4 6993.86 1203.69 0.7 11296 1199.41 4.6 6894.09 1203.65 0.8 11075.6 1199.8 4.8 6801.31 1203.61 0.9 10864.2 1200.16 5

6714.92 1203.57 1

10661.1 1200.5 5.2 6634.4 1203.51 1.1 10466.1 1200.81 5.4 6559.25 1203.46 1.2 10285.8 1201,09 5.6 6489.09 1203.41 1.3 10113.7 1201.36 5.7 5330.99 1204.35 1.4 9947.%

1201.6 5.8 5295.02 1204.33 1.5 9788.36 1201.83 5.9 5260.18 1204.3 1.6

% 34.6 1202.03 6

5226.45 1204.28 1.7 9486.43 1202.23 6.2 5162.17 1204.22 1.8 9343.61 1202.4 6.4 5101.98 1204.17 1.9 9205.91 1202.56 6.6 5045.66 1204.12 2

9073.11 1202.71 6.8 4992.97 1204.06 2.1 8945.03 1202.85 7

4943.68 1204.01 2.2 8821.44 1202.97 7.2 4897.59 1203.96 2.3 8702.17 1203.08 7.4 4854.52 1203.91 2.4 8587.07 1203.19 7.6 4814.19 1203.86 2.5 8475.94 1203.28 7.8 4776.31 1203.81 2.6 8368.65 1203.37 8

4740.6 1203.76 2.7 8265.04 1203.44 8.2 4706.75 1203.72 2.8 8108.69 1203.54 8.4 4674.49 1203.67 2.9 8021.53 1203.59 8.6 4643.51 1203.63 3

7937.45 1203.63 8.8 4613.57 1203.58 1

Attachment I to 2CAN099703 Page 21 of 65 i

Table 6 (continued)

MAIN STEAM LINE BLOWDOWN DATA USED IN THE MAIN STEAM LINE BREAK PEAK CONTAINMENT PRESSURE REANALYSIS TO JUSTIFY A LOWER MSIS AND RPS STEAM GENERATOR LOW PRESSURE SETPOINT 2ll TO MWt - 100 PERCENT BREAK AREA (6.19 SQ. FT.)

Time Mass Flow Enthalpy Time Mass Flow Enthalpy (sec.)

(lbm/sec.)

(Btu /lbm)

(sec.)

(Ibm /sec.)

(Btu /lbm) 9 4584.39 1203.54 34 2529.62 11 %.22 9.2 4555.72 1203.49 36 2458.48 1195.76 9.4 4527.31 1203.45 38 2387.86 1195.27 9.6 4498.97 1203.4 40 2302.4 1194.66 9.8 4470.56 1203.35 42 2214.95 1193.99 10 4441.93 1203.3 44 2130.15 1193.3 10.5 4368.88 1203.17 46 2049.32 1192.61 11 4293.21 1203.02 48 1971.84 1191.9 11.5 4215.2 1202.86 50 1896.97 1191.18 12 4135.88 1202.69 52 1824.4 1190.44 12.5 4056.77 1202.51 54 1754.05 1189.68 13 3979.55 1202.32 56 1685.64 1188.89 13.5 3905.65 1202.13 58 1619.02 1188.09 14 3836.24 1201.94 60 1553.63 1187.25 14.5 3772.27 1201,76 62 1516.79 1186.72 15 3714.16 1201.59 62.2 1510.57 1186.62 15.5 3661.89 1201.43 62.4 1499.76 1186.46 16 3615.01 1201.28 62.6 1480.5 1186.16 16.5 3572.73 1201.14 62.8 1444.68 1185.59 17 3534.04 1201.01 63 1368.45 1184.31 17.5 3497.7 1200.88 63.2 1223.12 1181.54 18 3462.49 1200.76 63.4 1093.68 1178.63 18.5 3427.57 1200.63 63.6 983.19 1175.7 19 3392.27 1200.5 63.8 889.31 1172.78 20 3319.26 1200.22 64 810.22 1169.92 22 3167.33 1199.58 64.2 744.62 1167.17 24 3027.74 1198.94 64.4 691.82 1164.65 26 2913.99 1198.38 64.6 651.7 1162.49 28 2811.46 1197.85 64.8 360.31 1161.4 30 2709.98 1197.3 65 634.5 1161.49 32 2613.05 1196.73 65.2 361.42 1161.44

Attachment ! to 2CAN099703 Page 22 of 65 Table 6 (continued)

MAIN STEAM LINE BLOWDOWN DATA USED IN THE MAIN STEAM LINE BREAK PEAK CONTAINMENT PRESSURE REANALYSIS TO JUSTIFY A LOWER MSIS AND RPS STEW GENERATOR LOW PRESSURE SETPOINT 2,770 MWt - 100 PERCENT BREAK AREA (6.19 SQ. FT.)

Time Mass Flow Enthalpy Time Mass Flow Enthalpy (sec.)

(Ibm /sec.)

(Btu /lbm)

(sec.)

(Ibm /sec.)

(Btu /lbm) 65.4 360.19 1161.4 71.8 61.97 1192.1 65.6 355.56 1161.25 72 59.51 1192.45 65.8 348.72 1161.01 72.2 57.9 1192.67 66 340.19 1160.72 72.4 56.89 1192.79 l

66.2 331.44 1160.42 72.6 56.29 1192.83 66.4 325 1160.2 72.8 55.97 1192.8 66.6 320.03 1160.03 73 55.84 1192.72 66.8 315.61 1159.87 73.2 55.82 1192.6 67 311.25 1159.72 73.4 55.89 1192.44 67.2 306.8 1159.56 73.6 56 1192.24 67,4 302.19 1159.4 73.8 56.14 1192 67.6 297.42 1159.23 74 56.31 1191.74 67.8 292.5 1159.05 74.2 56.%

1191.73 68 287.44 1158.87 74.4 57.75 1192.21 68.2 282.27 1158.68 74.6 58.15 1192.9 68.4 276.98 1158.49 74.8 58.15 1193.69 68.6 271.58 1158.29 75

-57.82 1194.52 68.8 266.07 1158.09 75.4 56.54 1196.24 69 260.45 1157.89 76 53.83 1198.84 69.2 254.69 1157.67 76.4 51.84 1200.55 69.4 224.11 1156.53 77 48.82 1203.14 69.6 196.31 1156.17 77.4 46.85 1204.89 69.8 174.85 1158.97 78 43.95 1207.61 70 159.84 1167.14 78.4 42.05 1209.51 70.2 144.78 1175.83 79 39.24 1212.51 70.4 128.23 1181.15 79.4 37.37 1214.61 70.6 112.52 1184.58 80 34.53 1217.91 70.8 98.67 1186.93 81 29.65 1223.69 71 87.1 1188.64 82 24.53 1229.6 71.2 77.85 1189.92 83 19.66 1233.68 71.4 70.78 1190.88 84 16.74 1236.64 71.6 65.61 1191.59 85 14.02 1239.2 7

Attachment I to 2CAN099703 Page 23 of 65 Table 6 (continued)

MAIN STEAM LINE BLOWDOWN DATA USED IN THE MAIN STEAM LINE BREAK PEAK CONTAINMENT PRESSURE REANALYSIS TO JUSTIFY A LOWER MSIS AND RPS STEAM GENERATOR LOW PRESSURE SETPOINT 2,770 MWt - 100 PERCENT BREAK AREA (6.19 SQ. FT.)

Time Mass Flow Enthalpy (sec.)

(Ibm /sec.)

(Buillbm) 86 11,46 1241.56 87 9.05 1243.93 88 6.72 1246.47 4

89 4.4 1249.25 89.2 3.93 1249.83 i

89.4 3.45 1250.42 i

89.6 2.97 1251.02 89.8 2.49 1251.62 90 2

1252.22 90.2 0

1252.22 4

Attachment I ts 2CAN099703 Page 24 of 65 Table 7 Summary ofInitial Containment Conditions Containment Initial Conditions Temperature Relative Pressure

(*F)

Humidity (%)

(psis)

MSLB LOCA 100 0

• 15.67 L

• 15.9 1C0 7

15.700 15.9

~

100 50 15.910 L 16.05 100 100 16.135 L fF 140 0

• 14.30 L

• 14.5 140 7

14.395 14.5 140 50 14.980 14.75 L 140 100 15.635 15.2 L

• This value was extrapolated for 0% relative humidity. The COPATTA code was limited to an initial relative humidity of 7%.

L These values represent the limiting initial containment pressures for the given temperatures and relative humidity.

~

Attachment I t3 2CAN099703 Page 25 of 65 i

Ttble8 ASSUMPTIONS FOR THE STEAM LINE BREAK ANALYSIS FROM HOT FULL POWER AND HOT ZERO POWER Parameter IJnita Assumptions Hot Full Power Hot Zero Power InitialIncore Power Level Mwt 2900 1

RCP Heat Mwt 10 10 Initial Core Inlet Temperature

'F 556.7 552 4

Initial Reactor Coolant Flow 10' lbm/hr 108.36 108.36 l

Initial Reactor Coolant System Pressure psia 2300 0 00 CEA Worth at Trip

%Ap

-7.5144

-5.0 e

Initial Steam Generator Pressure psia 922 1058 Doppler Coefficient 1.22 1.22 Moderator Temperature Coefficient 10" Ap/ F

-3.4

-3.4 Feedwater Regulating System Automatic Manual

Attaciiment i 13 2CAN099703 Page 26 of 65 Table 9 SEQUENCS OF EVENTS FOR Tile STEAM LINE BREAK IIOT FULL POWER WITII LOSS OF AC Time Event Setpoint or Yalue Seconds 0

Steam line b.eak occurs Loss of AC power occurs RCPs begin coasting down 0.31 CPC Low pump speed trip signal, fraction 0.965 1.31 Trip breakers open 1,91 CEAs begin to drop 620 2

MSIS setpoint has been reached, psia 3.3 MSIV begin to close 3.4 MFIV begin to close 6

Complete Closure of the MSIV 220 SG delta pressure isolation reached, psid 12.

I,1 tact 50 level reaches EFW actuation setpoint, % ornarrow 35.0 range 21 Pressurizer empties 1400 24.9 SIAS setpoint la reached, psia 37.6 EFW entersintact SG (steam pump) 38.4 Complete closure of the MFIV 64.9 SIAS pumps reach full speed and begin injecting 100.9 EFW to intact SG is increased (electric pump) 106.6 Boron reaches RCS 2.61 204 Maximum pou-trip fission power, % of 2815 Mwt 1.81 210 Minimum DNBR

-0.029 302 Maximum post trip reactivity, %Ap

<2510 325 Ruptured steam generator empties, Ibm 387.1 390 Cooldown ends, Minimum inlet temprature, 'F 500 End of calculation 1800 Operator initiates cooldown (not simulated)

Attschment I ts 2CAN099703 Page 27 of 65 Table 10 SEQUENCE OF EVENTS FOM TIIE STEAM LINE BREAK HOT FULL POWER WIT 2I AC AVAILABLE Time Event Scipoint or Value Seconds O

Steam line break occurs 620 2.07 SG low pressure trip condition and MSIS setpoint has been reached, psia 3.34 MSIVs begin to close 3.37 Trip breakers open 3.47 MFIV begin to close 3.97 CEAs begin to drop 6.34 Complete Closure of the MSIV:

220 7.1 SG delta pressure isolation reached, psid 13.7 Intact SG level reaches EFW actuation setpoint, % of narrow 35.0 range 17.2 Pressurizer empties 1400 18.67 SIAS setpoint is reached, psia 23.47 Complete closure of the MFIV 38.8 EFW enters intact SG(steam pump) 58.7 SIAS pumps reach full speed and begin injecting 4.98 80 Maximum post trip fission power, % of 2815 Mwt 2.46 80 Minimum DNBR 0.338 83 Maximum post trip reactivity, %Ap 405.1 84 Cooldown ends, Minimum inlet temperature, 'F 87.4 Boron reaches RCS 96.5 EFW to intact SG is increased (electric pump)

<2510 100.6 Ruptured steam generator empties, Ibm 350 End ofcalculation 1800 Operator initiates cooldown (not simulated)

Attachment I to 2CAN099703 Page 28 of 65 Table 11 SEQUENCE Of" W.*2NTS FOR TIIE STEAM LINE BREAK HOT ZERG POWER WITli LOSS OF AC Time Event Setpoint or Value Seconds O

Steamline break ocars Loss of AC power occurs RCPs begin coasting down l

0.32 CPC Low flow trip signal, Fraction of pump speed 0.%5 l

1.32 Trip breakers open 1.92 CEAs begin to drop 3.2 MSIS initiation setpoint has been reacf ed, psia 620 i

4.47 MSIV: begin to close 7.47 Complete Closure of the MSIV 8.8 SO delta pressure isolation reached, psid 220 27.3 Pressurizer empties 28.4 SIAS netpoint is reached, psia 1400 54.5 Emergency Feed valves clone 68.4 SIAS pumps reach full speed and begin injecting 106.7 Boron enters RCS

.252 159 Maximum post trip reactivity (first peak), %Ap 253 Maximum pca trip reactivity (second peak), %Ap

.126 334 Maximum post trip fission power, % of 2815 Mwt

.41 343 Minimum DNBR 12.3 555 Ruptured steam generator empties, Ibm

<2520 610 Cooldown ends, Minimum inlet temperature, 'F 269.4 650 End of calculation 1800 Operator initiates cooldown (not simulated) n

l Attachment I 19 2CAN099703 Page 29 of 65 Table 12 SEQUENCE OF EVENTS FOR TIIE STEAM LINE BREAK HOT ZERO POWER WITII AC AVAIIABLE Time Event Setpoint or Value Seconds O

Steam line break occurs 620 3.22 50 low pressure trip condition and MJ:3 initiation setpoint has been reached, psia 4.49 MSIVs begin to close 4.49 Trip breakers open 5.09 CEAs begin to drop 7,49 Complete Closure of the MSIV 220 8.8 SG Delta pressure isolation reached, psid 20.3 Pressurizer empties 1400 20.94 SIAS setpoint is reached, psia 39.52 Emergency Feed Valves close 61,0 SIAS pumps reach full speed and begin injecting 87.3 Boron enters RCS

.227 122 Maximum post trip reactivity, %Ap 1.275 145 Maximum post trip fission power, % of 2815 Mwt 11.2 145 Minimum DNBR

<2500 146 Ruptured steam generator empties, Ibm 348.6 146 Cooldown ends, Minimum inlet temperature, 'F 250 End ofcalculation 1800 Operator irdtiates cooldown (not simulated)

Attachment i 13 2CAN099703 Page 30 of 65 Table 13 I

I Updated Physical Data For Isotopes Average Energy Thyroid Dose Isotope IIalf Per disintegration Conversion l

Symbol Life (MeV/ Dis)

Factor Gamma Beta (rem /pCi)

(DEQm) 1131 8.1d 0.372 0.195 1.480 1.000 1132 2.3h 2.390 0.422 0.0535 0.0362 1133 20 h 0.639 0.408 0.400 0.2703 1134 52 m 1.830 0.548 0.025 0.0169 I135 6.7h 1.770 0.308 0.124 0.0838

1 Attachment I to 2CAN099703 i

Page 31 of 65 Table 14 ASSUMPTIONS FOR THE FEEDWATER LINE BREAK ANALYSIS I

Conservative Parameter Unita Assumptions initial Core Power Level (MWt) 2900 RCP lient (MWt) 18 Core inlet Coolant Temperature

('F) 556.7 Reactor Coolant System Flow (10'lbm/hr) 120.4 Reactor Coolant System Pressure (psla) 2005 Steam Generator Pressure (ysia) 910 Moderator Temperature Coefficient (10 Ap/*F) 0 Doppler Multiplier 0.85 CEA Worth on Trip

(% Ap)

-5.0 Steam Generator tube Plugging 0

Tolerance on MSSV Setpoint 3

Tolerance on PSV Setpoint 3

i

1. r--

Attachment I t3 2CAN099703 Page 32 of 65 Table 15 SEQUENCE OF EVENTS FOR TIIE FEEDWATER LINE BREAK ACCIDENT WITil LOSS OF AC Time Event Setpoint or Seconds Value 0

Rupture of the Main Feedwater Line 44.3 Low Steam Generator Water Level Trip Condition on intact 5%

Steam Generator Occur Actuation of the Emergency Feedwater Signal Downcomer Empties on Ruptured Steam Generator 44.7 Iligh Pressurizer Pressure Trip 2422 psia 45.6 Trip Breakers Open, Loss of AC Power Occurs, RCPs Begin Coasting Down 46.2 CEAs Begin To Drop 46.5 Pressurizer Safety Valves Start to Open 2575 psia 48.8 Main Steam Safety Valves Open on the Intact Steam Generator 1125.5 psia 49.2 Main Steam Safety Valves Open on the Affected Steam Generator 1125.5 psia 49.2 Maximum RCS Pressure Occurs 2730.1 psia 53.0 Pressurizer Safety Valves Close 2472 psia 58.0 Affected SG Goes Dry 61.0 Main Steam Safety Valves Clor,e on the Affected Steam Generator 1069 psia 76.0 Main Steam Safety Valves Close on the Intact Steam Generator 1069 psia 233.1 Steam Generator Low Pressure Trip Condition and MSIS Initiated 620 psia 234.4 Main Steam Isolation Valves Begin to Close 237.4 Complete Closure of Main Steam isolation Valves Terminating Blowdown from the Intact Steam Generator 269.4 Emergency Feedwater Enters Intact Steam Generator 270.0 Minimum Liquid Mass in the Steam Generator Connected to Intact Feedline 448.0 Main Steam Safety Valves Open on the intact Steam Generator 1125.5 psia (Begin Cycling, Long Term) 600 Case Terminated

Attachment I to 2CAN099703 Page 33 of 65 Figure 1 Cooldow.) Data for the Cycle 13 MSLB Analysis 0.05 008--

HFP 0.07--

^ 008-0.06 -

0 04 --

0 03 -

0.02 -

HZP 0 01 --

1 E

I O

100 300 300 400 500 50 ModeratorTemperature(F)

Attachment I to 2CAN099703 Page 34 of 65 Figure 2 Doppler Reectivity wereue Fuel Temperature for the Cycle 13 MSLB 0 03 0 025 0 02 -

i

-j 0 015 -

0 01 E

0 006 -

0-401 4 015 0

200 400 000 800 1000 1200 1400 1800 Fuel Temperature (F)

Attachment I t3 2CAN099703 Page 35 of 65 Figure 3 Reactivity insertion versus CEA Insation 4.00 4.N -

4.M -

4.m 4.92 -

4.01 0.00 0

05 1

1.5 2

2.5 3

35 4

Time (sec)

Attachment I t3 2CAN099703 Page 36 of 65 Figure 4 SLB IIFP Loss of AC 111 PSI Core Power vs. Time 4

6' 1.20

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Attachment i 13 2CAN099703 Page 37 of 65 Figuet 5 SLB liFP Loss of AC 1 HPSI Heat Mux vs. Time 1.20 m s

.....s......

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_ _. to 2CAN099703 Page 38 of 65 Figure 6 SLB HFP Loss of AC 1 IIPSI Pressurizer Pressure vs. Time i

2400.....,.

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Attachment I to 2CAN099703 Page 39 cf 65 Figure 7 SLB HFP Loss of AC 1 HPSI Steam Generator Pressure vs. Time SG 1

.............SG2 1200

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4 1000 7

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- LS 2CAN099703 Page 40 of 65 l

Figure 8 SLB IIFP Loss of AC 1 IIPSI RCS Temperatures vs. Time Thot

............. Tmod av Tin i''''6''''i''''l'

600

.J

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Attachment I ta 2CAN099703 Page 4I of 65 i

Figure 9 f

SLB IIFP Loss of AC 1 HPSI Reactivities vs. Time Total Moderator

............. Doppler Boron scram Hermite credit 0.09

..........s.........s.......

.\\.........s.........

0.06.

~

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Attachment I to 2CAN099703 Page 42 of 65 4

Figure 10 SLB HFP AC Available 1 HPSI Core Power vs. Time 1.20

..........s

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Attachment I t) 2CAN099703 Page 43 of 65 Figure 11 SLB I!FP AC Available 1 IIPSI Heat Flux vs. Time i

1.20

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70 140 210 280 350 Time (Seconds)

Attachment i 13 2CAN099703 Page 44 cf 65 Figure 12 4

SLB HFP AC Available 1 HPSI Pressurizer Pressure vs. Time 2400

.........s s.........s.........s.........

e e

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Attachment i 19 2CAN099703 Page 45 cf 65 Figure 13 SLB IIFP AC Available i HPSI Steam Generator Pressure vs. Time SG 1

............'SG2 1200........i.........i.........i........i.

1000 ?

1 l l.

800 T;

rl

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Attachment I to 2CAN099703 Page 46ef 65 Figure 14 SLB IIFF AC Availsble 1 HPSI RCS Temperatures vs. Time Thot

............. TM av Tin

.s.........s.........s.........

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....s L

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Attachment I to 2CAN099703 Page 47 of 65 Figure 15 SLB IIFP AC AvaHable 1 HPSI Reactivities vs. Time Total Moderator

............. g,,

. Boron

. Scram Hermite Credit 0.09

..........s......

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. to 2CAN099703 Page 48 cf 65 Figure 16 SLB IlZP Loss of AC 1 IIPSI Core Power vs. Time (Semi Los scale) o 10 p......

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. 13 2CAN099703 Page 49 cf 65 Figure 17 SLB IIZP Loss of AC 1 IIPSI IIeat Flux vs. Time (Semi Log scale) o 10.

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Attachment I t2 2CAN099703 Page 50 of 65 Figure 18 SLB IIZP Loss of AC 1 HPSI Pressurizer Pressure vs. Time 2400.............................

es S

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I Attachment I to 2CAN099703 Page 51 of 65 1

1 Figure 19 SLB HZP Loss of AC 1 HPSI Steam Generator Pressure vs. Time l

SG1

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s.

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Attachment I te 2CAN099703 Page 54 of 65 Figure 22 SLB HZP AC Available 1 HPSI Core Power vs. Time (Semi Log scale) o 10 -.........s..

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Attachment ! to 2CAN099703 Page 55 cf 65 Figure 23 SLB HZP AC Available 1 HPSI Heat Flux vs. Time (Semi Log scale) c 10 :

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Attachment I to 2CAN099703 Page 56 cf 65 Figure 24 SLB HZP AC Available 1 HPSI Pressurizer Pressure vs. Time 2400.....

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Attachment I to 2CAN099703 Page $7 of 65 4

Figure 25 4

SLB HZP AC Available 1 HPSI 4

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Attachment I to 2CAN099703 -

Page 58 cf 65 Figure 26 SLB HZP AC Available 1 HPSI RCS Temperatures vs. Time Thot

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Attachment I to 2CAN099703 Page 59 of 65 l

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Figure 27 SLB HFP AC Available 1 HPSI i

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Attachment I to 2CAN099703 Page 60 of 65 Figure 28 Doppler Reactivity versus Fuel Temperature 4.1 4.M -

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l to 2CAN099703 Page 61 cf 65 Figure 29 Cycle 13 Feedwater Lise Rupture With Less of AC Core Power vs. Time 120 96 E

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Attachment I ts 2CAN099703 Page 62 of 65 Figure 30 Cycle 13 Feedwater Une Rupture With Loss of AC Core Heat Mux vs. Time 20 q

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Attachment I to 2CAN099703 Page 63 of 65 Figure 31 Cycle 13 Feedwater Line Rupture With Loss of AC Reactor Coolant Sptem Pressure vs. Time 2800 5

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Attachment I te 2CAN099703 Page 64 of 65 4

Figure 32 Cycle 13 Feedwater Ilse Rupture With Loss of AC Reactor Coolant System Temperature vs. Time 700 g

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Figure 33 Cycle 13 Feedwater Line Rupture With Loss of AC Steam Genentor Pressure vs. Time 1200 I

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