Text

Long Term Cooling Analysis for South Texas Project. Revs to Be Incorporated Into Future FSAR Amend Encl
	ML20215C022
Person / Time
Site:	South Texas
Issue date:	09/01/1986
From:	; WESTINGHOUSE ELECTRIC COMPANY, DIV OF CBS CORP.
To:	;
Shared Package
ML19292F992	List: ML20210Q647; ML20210Q685; ML20215B637; ML20215C022; ML20215C032; ST-HL-AE-1767, Comparison of Treat & Notrump Small Break LOCA Transient Results;
References
	ST-HL-AE-1767, NUDOCS 8610100047
	Download: ML20215C022 (88)
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ATTACHMENT l ST HL-AE 1%7 PAGE I OF g(o LONG TERM COOLING ANALYSIS FOR SOUTH TEXAS PROJECT September 1986 Westinghouse Nuclear Technology Systems Division 8610100047 860930 PDR ADOCK 0500 8

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ATTACHMENT /

ST HL AE-I?r,7 PAGE.L OFgfo LONG TERM COOLING ANALYSIS FOR SOUTH TEXAS PROJECT F.A92 Section 2

1 Introduction and Summary 6

Description of Long Term Cooling Modeling Assumptions 2

6 Safety Grade Features of the South Texas Plant 2-1 10 2-2 South Texas TREAT Model 16 Operator Actions used in the Recovery 2-3 17 3

Detailed Analysis 19 1.5 Inch Diameter Cold Leg Break 3-1 43 0.7 Inch Diameter Cold Leg Break 3-2 62 3-3 Feedline Break 85 4

References l

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ATTACHMENT /

ST-HL AE-lM PAGE S OF86 Section 1 Introduction and Summary NRC RSB Questions 440.38 and 440.39 raised concerns re?arding the adequacy of the South Texas Project (STP) design for providing long term cooling capability following a small LOCA.

In particular, for very small LOCAs, the situation Vas postulated where the energy removed by the break / makeup flow path may not be adequate for decay heat removal but the supply of safety grade auxiliary feedwater in the AFST could be exhausted.

Additionally, if low-head SI or RHR System operation was to be the long term cooling mode, how would RCS depressurization be accomplished using only safety grade equipment.

The analysis described in this report supports the South Texas design for long term cooling capability for a spectrum of small LOCAs, including isolatable LOCAs and secondary breaks.

This is accomplished by demonstrating acceptable recovery using only safety grade equipment and assuming conservative operator actions.

All analyses were based on assumptions of 10CFR50 Appendix K, restricted to situations not involving ccre uncovery.

The three cases analyzed and a summary of their significance is as follows:

Case 1.

A 1.5 inch diameter cold leg break with minimum safety injection.

Operator actions include cooldown using the SG PORVs of two active SGs receiving AFW, depressurization of the inactive SGs to limit flashing in the inactive loops, switchover to high-head recirculation, and termination of high-head SI to allcw low-head SI makeup.

The long term cooling analysis was performed l

using TREAT (Transient Eeal-time Engineering Analysis Tool).

The l

first one hour portion of a similar 1.5 inch break transient, STP specific, has been compared with the Westinghouse small break ECCS evaluation model (NOTRUMP) to demonstrate the adequacy of TREAT for small break LOCA without core uncovery (Ref. 1).

The complete analysis performed for long term cooling was then run for 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months using TREAT.

Analysis assumptions used for this case (and Cases 2 and 3) were consistent with 10CFR50 Appendix K requirements.

This includes 102% initial power and 120% ANS-5-1971 decay heat (Ref.

5).

At the end of the 7 hour8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months run, it was possible to extrapolate that the break / low-head SI flow path would be adequate for all decay energy removal after 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

Based on conservative decay heat estimates of the revised standard ANS-5.1-1979 (Ref. 7),

break /LHSI energy removal was demonstrated at 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months .

Additionally, it was demonstrated that RHR entry conditions are established at the end of the 7 hour8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months transient.

Therefore, this analysis demonstrates that for larger break cases, the break /IRSI flow will remove all decay energy.

It also demonstrates that for smaller break cases, LHSI makeup in coincidence with RHR system operation (for supplemental cooling) will provide adequate decay heat removal.

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AYYACHMENT /

ST HLN OFg6 AE /7V/

PAGE Case 2.

A 0.7 inch diameter cold leg break with minimum SI but no spill.

With the smaller break size and additional SI, the post-LOCA recovery includes stopping of high-head SI pumps and the operation of one pressurizer PORV for RCS pressure and inventory control.

Other recovery actions are similar to those used for the 1.5 inch cold leg break, i.e.,

cooldown with the SG PORVs on the two active SGs and occasional depressurization of the inactive SGs to prevent flashing.

For this 7 hour8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months scenario, LHSI makeup is established before switchover (only 168,000 gallons is used out of a usable RWST volume of 354,000 gallons prior to switchover).

The AFST depletion is only 133,500 gallons (out of a usable volume of 445,000 gallons) when RHR entry conditions are established.

The makeup flow required at the end of this transient is also less than the capacity of one of the centrifugal charging pumps.

Caso 3.

Feedline Break.

This case is intended to bound isolatable LOCAs and all secondary breaks as the limiting heatup event for AFST depletion.

The analysis for this case is similar to the Chapter 15 FSAR feedline break analysis (Ref. 3) which was based On AFW flow to one intact SG and AFW spill from the faulted SG.

The TREAT and FSAR analysis heatup rate and maximum temperature (640 F) were approximately the same, up until the time that the SG PORV cn the active SG was opened to control RCS ter.perature (a required action specified in the FSAR).

At the end of the four hour hot standby period, AFW cross-connects were opened to establish feedwater to another SG.

A fourteen hour cooldown was then performed using the SG PORVs on the two active SGs.

Following the cooldown, the RCS was depressurized to RHR cut-in conditions (less than 350 psig) using the reactor vessel head vent.

After 21 hours2.430556e-4 days 0.00583 hours 3.472222e-5 weeks 7.9905e-6 months , the AFST depletion (including the initial 30 minute spill from the faulted SG) was 396,300 gallons.

This leaves a margin of 48,700 gallons in the AFST.

This allows at least four additional hours or 25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months total.

If the analysis had been based on the ANS-5.1-1979 decay heat, the cerresponding l

margin would be greater (more than 100,000 gallons).

Thus, for this limiting AFST depletion event, it was demonstrated that the AFST inventory is sufficient for decay heat removal before the RHR System needs to be placed in service.

It was also demonstrated in this analysis that no upper head cooling soak time is required prior to RCS depressurization to RHR if the cooldown rate is maintained less than or equal to 25 F/hr.

Using the information from these analyses, it is possible to construct a map outlining the recovery actions used for various SI pump configurations as a function of break size.

This diagram is presented in Figure 1-1.

Points from the three analyses are also indicated.

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ATTACHYENT /

ST Hi.-AE-176 7 PAGE 5 OF B6 The assumptions and detailed analysis are presented in the remaining sections of this report.

In Section 2, the South Texas safety grade equipment used and TREAT model assumptions are briefly described.

Operator actions based on Rev. 1 of the Westinghouse Owners Group Emergency Response Guidelines (ERGS),

Low-pressure version (Ref. 4) are also briefly described in terms of how they apply for the safety grade recovery actions assumed.

Section 3 presents the detailed analyses.

Major actions and expected ERG application for each of the three cases are discussed in the write-up for each analysis.

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ATTACHMENT I ST-HL-AE 176'l PAGE 6 OF f6 1.

1.5" CL Break with Min SI 2.

0.7" CL Break with Min SI (w/o spill) 3.

Feedline Break Max SI -

SG PORVs.

PRZR PORVs.

Stop all HHSI, Stop all NHSI.

Stop all HHSI.

LHSI Makeup.

3 HHSI Charging or LHSI Makeup.

LHSI/ Break LHSI Makeup.

RHR Cooling.

Cooling.

/

RHR Cooling.

Head Soak if Required (not 2 HHSI -03 expected).

0 2.

I I

1 HHSI l

I Min SI g

l l

1 l

I I

0.

.375

.75 1.0 1.5 Break Size Diameter (Inches)

Figure 1-1 STP Recovery Actions and Long Term Cooling Modes for various Break Sizes and High-head SI configurations 4

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ATTACHMENT /

ST-HL AE lq9 PAGE 7 OFy6 Section 2 Description of Long Term Cooling Modeling Assumptions 2-1 Safety Grade Features of the South Texas Plant The following subsections discuss the safety grade equipment used for long term cooling.

Safety Iniection System Descriotion South Texas has a three train low pressure SI system consisting of three high-head SI (NHSI) pumps, three low-head SI (LHSI) pumps, and three accumulators.

Each train is aligned to a separate loop.

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Loop 4 (or D, also the pressurizer loop), plus any loop associated with a failed bus will not receive SI flow.

The approximate pressure ranges for high-head and low-head safety injection are 0-1500 psig and 0-300 psig, respectively.

The comparison of the d minimum SI used in the analyses, along with best estimate high-head SI flow to one loop is given in Figure 2-1. The minimum SI curve in this figure was used in the TREAT /NOTRUMP comparison analysis of Reference 1.

Revised flowrates based on recent testing are within (+/-) 4% of the flowrates presented in this figure.

A comparison of the new and old mininimum SI curves is given in Figure 2-2.

The TREAT long term cooling analysis presented in this report is based on the revised minimum SI curves.

During recirculation, the LHSI and HHSI pumps take suction directly from the sump.

The LHSI flow is cooled by an RHR heat exchanger before returning to the RCS.

The HMSI flow goes directly into the RCS.

j Auxiliary Feedwater System Descriotion The plant has three motor driven AFW pumps and one turbine driven AFW pump.

In the normal alignment, each AFW pump is aligned to one SG.

Tech Specs also allow one AFW pump (Train A) to be out of service.

The AFW system does not have a common header, however, there are normally-closed, fail-closed cross-connects between AFW lines that can be opened to permit flow from one AFW pump to two or more SGs.

Since SI reset is required for operation of the cross-connect valves and EOP actions to reset SI might be delayed until a 1

non-fed SG is dried-out, the small LOCA recovery actions will not l

assume operation of cross-connect valves.

As explained in Section l

3-1 of Ref.

1, at least 2 SGs will receive AFW flow for a small I

LOCA, with a limiting single failure included.

The PORVs on these two SGs are used to cooldown to RHR cut-in conditions (350 F, 350 i

psig).

Intermittent operation of the SG PORVs on the inactive SGs is also performed to limit flashing in the inactive loops during j

RCS depressurization.

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ATTACHMENT /

ST.HL-AI- / 76 7 PAGE 8 0F f(

Tor the feedline break modeled, it is necessary to open AFW cross-connects to ensure feed flow to two intact SGs.

For this condition 4 accident, this action is not completed before the two intact SGs without AFW dry out.

If it is necessary to restore feed flow to one of the intact SGs to ensure at least two intact active SGs are avaliable, EOP guidance and training will instruct the operator to restore feed to the SG with the higher WR level indication.

This will minimize any potential SG integrity Concern.

Steam Generator PORV Operation - Active Loons The SG PORVs (power-operated relief valves) are electro-hydraulically operated and are safety grade.

Emergency bus A is needed to operate the hydraulic pumps required to operate the SG PORVs on SG A and SG D; busses B and C are needed for the PORVs on SG B and SG C, respectively.

Steam Generator PORVs - Inactive Loops The SG PORVs on the inactive loops were not assumed to be operable until late in the transients.

The earliest assumed use (0.7 inch break case) was 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months after reactor trip or 1.4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after the controlled cooldown was initiated using the active SGs.

Since local actions required for inactive SG PORV operation can be performed in one to two hours, the analysis assumption is reasonable.

In the 1.5 inch break case, the inactive SG PORVs were operated approximately 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months after reactor trip.

In the feedline break scenario, the SG PORVs on the inactive loops (1 and 4) did not have to be operated.

It is possible that the PORV of one of the SGs used for the post-feedline break cooldown would not have AC power to operate the hydraulic pump.

Local actions, if required, are within the capability of plant operations and would not be needed until the last hour of the four hour hot standby period.

Other Safety Grade Eauipment There are two safety grade pressurizer PORVs in each South Texas Plant.

Operation of one pressurizer PORV is assumed in the

(.

analyses to achieve RCS depressurization since normal pressurizer spray is not available.

Operation of one pressurizer PORV also has priority over use of auxiliary spray if letdown is not in service in the ERGS.

This avoids potential thermal shock to the

. spray nozzles.

Auxilary spray and letdown are not safety grade equipment.

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ATTACHMENT /

/767 ST.HL,g 0F f6 PAGE 7 One of the two safety grade charging pumps was used to provide charging and RCP seal injection for the feedline break recovery.

In this analysis, the charging pump was started late in the transient (at 50 minutes) to allow for possible time delay for local throttling control (specifically CCP No. 1 loaded on bus C).

For seal injection flow alone, this delay would not be required.

In the small LOCA transients, no credit was taken for charging pump operation.

To maintain containment pressure and temperature within acceptable limits, operation of 3 of the 6 reactor containment fan coolers (RCFCs) was assumed.

This allows for failure of one train and one RCFC unit initially out of service.

For a large secondary break, containment spray actuation would also occur.

Sprays can later be stopped after SG blowdown is over.

The remaining piece of safety grade equipment used in the long term cooling analysis is the reactor vessel head vent.

This safety grade letdown path was used briefly during the four hour hot standby period in the feedline break recovery to reduce RCS pressure.

The head vent was also used to depressurize to RHR cut-in pressure.

Table 2-1 summarizes the equipment used in the three analyses performed for long term cooling.

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ATTACHMENT /

ST HL-AE /767 PAGE /0 0F FG Table 2-1 Summary of Safety Grade Equipment Used for the Long Term Cooling Recovery 1.5" Break O.7" Break Feedline Break Type of Accident Condition 3 Condition 3 Condition 4 Eauipment Used 675 gpm spill AFW Flow 540 gpm-SG2 540 gpm-SG2 540 gpm split Capability 540 gpm-SG3 540 gpm-SG3 to SG 2 &3 HHSI flow Spill Loop 2 Inject to SIAS but no Assumed Inject to 3 Loops 2 & 3 injection (LP)

Fail Loop 1 Fail Loop 1 LHSI flow Loop 3 Loop 3 (or 2)

Not used Inject to Not used Not used Accumulators Loops 1 & 3 EOPs permit EOPs permit Spill Loop 2 Isolation Isolation Makeup during l

Charging Flow Not used Not used.

cooldown.

Possible long Boration and RCP term makeup seal injection (optional) in hot standby.

SG PORVs SG 2 SG 2 SG 2 Active Loops SG 3 SG 3 SG 3 SG PORVs SG 1 & 4 SG 1 & 4 SG 1 & 4 Inactive Loops Used 3 hr Used 2 hr Not Used and when used after Rx trip after Rx trip PRZR FORV Not used Used Not used RCFCs Used Used Used L

Containment Spray Not Req'd Not Req'd Possibly Req'd for Short Term Used during hot Vessel Head Vent Not used Not used standby and for RCS depress. to RHR cut-in.

RHR System Optional Can be placed Can be placed Operation and min after 7 hr in service in service time to place in (Break /IESI after 7 hr after 21 hr service cooling is adequate) 9

i ATTACHMENT /

ST-HL RE-I'/(o ?

PAGE // OF 86 2-2 South Texas TREAT Model Reference 1 describes in considerable detail the various TREAT molels used and also provides noding diagrams for the South Texas TREAT model.

Brief summaries of the primary and secondary STP models are repeated in Tables 2-2 and 2-3.

For the three long term cooling analyses, a 10CFR50 Appendix K version at 3903 MWt reactor power (more than 102% licensed core power) and 120%

ANS-5-1971 decay heat was used.

This version along with the NOTRUMP comparison is repeated here in Table 2-4.

All analyses were based on the Appendix K decay heat assumptions.

Evaluations based on ANS-5.1-1979 (+2 sigma uncertainty) were included with two of the cases (1.5 inch break and feedline break) to demonstrate the conservatism in the analyses.

Additional information on the TREAT model is provided in the detailed analysis discussion and may also be found in Reference 1.

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ATTACHMENT l ST HL AE-1767 PAGE /AOF JG, Table 2-2 South Texas Plant Data used in TREAT Primary System Reactor Coolant System:

Number of Coolant Loops and RCPs 4

4 RCS Core Flow Rate 3.93x10gbm/sec Total RCS Volume (excluding pressurizer) 11200 ft Core Tavg - 100% power 596.6 F Tavg - no-load 567 F Thot/Tupper head - 100% power 629.2 F/622.7 F Upper Head Flow - 100% power 153 lbm/sec Licensed Core Power 3800 MWt

-(3917 MWt-NSSS)

Pressurizer:

3 Volume 2100 ft Total Heater Capacity 2100 kW Level - 100% Power 60%

Level - no-load 25%

Nominal pressurizer pressure 2235 psig Pressurizer PORVs:

Number and Flow Rate at 2335 psig setpoint 2 at 58.3 lbm/sec (per valve) s Pressurizer Safety Valves:

Number and Flow Rate at 2485 psig setpoint 3 at 116.7 lbm/sec (per valve)

Charaina and Letdown Flows Normal Letdown Flow 100 gpm Best Estimate Normal Charging to RCS 1 pump at 2235 psig (max flow, excludes 145 gpm approx. 12 gpm seal return flow)

Reactor Protection System:

Low Compensated Pressurizer Pressure Trip 1870 psig Low Pressurizer Pressure SI Actuation 1850 psig Low-low SG NR Level Trip 33%

Other Setpoints modeled:

OT delta-T, OP delta-T Low SL Pressure, et. al.

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ATTACHMENT I GE lYOYk Table 2-3 South Texas Plant Data used in TREAT Secondary System Steam Generators:

Number / Type 4 U-tube Model E Steam Pressure - 100% power 1085psgg Volume, each SG 8012 ft Narrow Range Level - 100% power 58.6 %

Steam Flow Rate, each SG 1200 lbm/sec Number of U-tubes, each SG 4864 (Unit 1) 4851 (Unit 2)

Tube I.D.

0.0553 ft Tube Plugging Assumed 5% (Unit 1 modeled)

Steam Line:

3 Steamline Volume to MSIV 1485 ft (calculated for one SL, used for all)

Atmospheric Steam Dump Valves:

l Number per SL/ Capacity at 1285 psig 1 at 250 lbm/sec Flow Rate at 85 psig 18.9 lbm/sec Safety Valves:

Number / Lowest to Highest Setpoints 5 / 1285 to 1325 psig Flow Rate per valve at 1285 psig 287 lbm/sec condenser Steam Dump and Bypass Capacity 40% of full power (all 12 valves)

Auxiliary Feedwater System:

Number of Motor-Driven AFW Pumps / Capacity 3 at 550-675 gpm/ pump (MD AFW feeds A,B,and C SGs)

Number of Turbine-Driven AFW Pumps / Capacity 1 at 550-675 gpm (TD AFW feeds D SG)

Note:

One AFW pump is dedicated to one SG.

Cross-connects can be opened to supply two or more SGs from one AFW pump.

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ATTACHMENT I ST.HL-AE 1761 PAGE 14 0F#6 Table 2-4 TREAT /NOTRUMP Initial Condition Comparison for 1.5 Inch Cold Leg Break Comparison Analysis

TREAT NOTRUMP RCS Pressure (psia) 2286.25 2280.54 SG Pressure (psia) 997.43 984.48 Reactor Power (MWt) 3903 3876 Core Flow (lbm/sec) 39172.3 38673.9 Upper Head Flow (lbm/sec) 152.241 154.305 Total Steam Flow (lbm/sec) 4805.2 4753.7 Pressurizer Level (ft) 58.53 (65.8%)

59.61 Cold Leg Temperature (F) 563.4 559.5 Core Exit Temperature (F) 629.6 626.4 Upper Head Temperature (F) 621.8 622.3 Break Area (sq-ft) 0.0123 0.0123

This TREAT initialization was also used for the 0.7 inch cold leg break (0.00267 sq-ft) and feedline break analyses.

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' ATTACHMENT /

ST HL-AE 1767 PAGE IS OF %

Figure 2-1.

Comparison of Minimum and Best Estimate Safety Injection loco.

1700.

"N 1-Minimum SI Flow to One Loop isoc.

s 2-Best Estimate HHSI Flow to One Loop s

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o 50 too 150 200 250 300 no 800

So 500 550 soo Safety Injection Flow (lbm/sec)

Note: These flows are consistent with recent test results, typically to within 44.

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ATTACHMENT I ST HL-AE-17/o7 PAGE 16 OF 6(o Figure 2-2.

Comparison of South Texas Minimum SI Flows 1-Minimum SI used in TREAT /NOTRUMP Comparison (Ref.1) 2-Revised Data Based on Recent Testing (Used in Long Term Cooling Analysis)

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Safety Injection Flow (lbm/sec) 15

ATTACHMENT I ST HL AE-1967 PAGE 17 0/gn 2-3 Ooerator Actions used in the EOPs The size of the LOCAs analyzed in this report (1.5 inch and 0.7 inch diameter) is small enough that both cases may be regarded as ANS Condition 3 events.

The FSAR feedline break is a Condition 4 event.

For these events, ANSI /ANS-58.8-1984 (Ref. 8) specifies the following minimum times for nuclear-safety related operator i

actions after a design basis event alarm (here assumed to be reactor trip):

Condition 2 5 minutes Condition 3 10 minutes Condition 4 and 5 20 minutes i

For the small LOCA scenarios, no safety related operator actions are assumed for at least 20 minutes following trip.

The feedline i

break analysis conservatively assumes no such actions for 30 i

minutes.

These times are consistent with the earlier more conservative version of Ref. 8 (i.e., ANSI N660, Jan. 1977) l' Operator action times based on the ERGS Validation and i

Verification tests typically' support mush shorter times (Ref.

l 9).

For example, an intermediate size LOCA (initially 3000 gpm, similar to the 1.5 inch break case) had the following operator action times (from time of reactor trip) when tested on the simulator.

Step numbers have been converted from high-pressure to low-pressure ERGS since STP follows the L.P. ERGS:

i 2 min, 50 sec:

E-0, Step 20 (Cooldown to no-load temp) 5 min, 3 sec:

E-1, Step 3 (Control SG levels with AFW) l 11 min, 20 sec:

ES-1.2, Step 3 (Start one charging pump) i 13 min, 14 sec:

ES-1.2, Step 5 (Start 100 F/hr cooldown)

(Note: Start one charging pump in ES-1.2 is unique to the L.P.

ERG.

The time noted here represents the time at which Step 3 was reached in the H.P. test.)

The first safety related operator action assumed in the small LOCA analyses is the cooldown in ES-1.2, Step 5.

This action is considered safety related only in the sense that cooldown and depressurization to RHR conditions is eventually needed because of the finite size of the AFST.

No credit is taken for the initial cooldown in E-0.

When the cooldown is started after 20 minutes (versus 13 minutes above), it is performed at 50 F/hr to allow margin to the 100 F/hr rate allowed.

Thus, the analysis considers operator actions that are more conservative than '

expected.

Similar conservatisms can be demonstrated for the feedline break scenario.

Additional details are provided in the following sections.

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ATTACHMENT I ST HL-AE-1%7 PAGE If OF 16 Detailed Analysis Before discussing the analysis in this section in more detail, the expected plant response for a number of variations of the 1.5 inch diameter cold leg break case will first be described.

Of the three breaks analyzed for long term cooling, the 1.5 inch break case has the largest break area and the greatest amount of RCS voiding.

The plant response will differ based on the assumed operator controlled cooldown rate, however, core uncovery will not occur.

The following cases are considered:

i.5" cold leg break with 100 F/hr cooldown 1.5" cold leg break without cooldown (no operator action) 1.5" cold leg break with 50 F/hr cooldown 1.5" cold lea break with 100 F/hr cooldown The first hour of this case was the topic of Reference 1.

A 100 F/hr cooldown rate is the maximum allowed in the post-LOCA recovery guideline.

By starting this cooldown at 1500 sec, two-phase natural circulation flow was maintained in the two active loops for the duration of the transient.

Only the tops of the SG U-tubes in these loops became voided.

The RCS depressurized with the active SGs and at the end of the hour, break flow approximately matched SI flow (about 100 lbm/sec) at the " equilibrium" pressure, 900 psia.

The loop seal piping (i.e., the low horizontal section at the RCP suction) remained filled in all loops and the core remained covered with at least five feet of water above the top of the active fuel.

1.5" cold lea break without cooldown This case was not analyzed specifically for STP with either NOTRUMP or TREAT since it is possible to predict the expected core response based on the results of an existing 2" diameter l

break case for the SNUPPS plant.

This case is reported in the l

NOTRUMP generic studies of Reference 2.

A comparison of some of the relevant parameters is presented below:

SNUPPS 2" South Texas 1.5" Core Power as Analyzed (MWt) 3579 3876 SI Flow at Lowest SG Safety 50 40 Valve Setpcint (lbm/sec)

SI Flow at 1000 psia (lbm/sec) 60 90 Break Flow at Lowest SG Safety 210 110 Valve Setpoint (lbm/sec)

Lowest SG Safety Valve 1190 1300 Satpoint (psia)

Time Loop Seal Clears (sec) 1350 2800 (estimate) 17

ATTACHMENT I ST HL AE 1%7 PAGE R OF8L The minimum core mixture level for the SNUPPS 2" break was 2 feet above the top of the active fuel.

Since the vessel geometry, loop geometry, and top of core elevations for STP are very similar to SNUPPS, the minimum core mixture level for the STP 1.5" break is estimated to be 2 to 4 feet above the top of the active fuel.

This estimate and the loop seal clearing time estimate were based on reasoning that the 1.5" break for STP would behave similar to the 2" break for SNUPPS except the time would be shifted by roughly a factor of two.

The reason for this shift is that the break flow minus SI flow difference (at RCS pressure equal to SG safety valve pressure) differ by a factor of two for the two cases.

Consequently, the RCS would drain down and the loop seal would allow the break to vent steam at roughly double the time for STP.

After the loop seal clears, the RCS depressurizes, which causes increased SI flow.

Due to the substantial increase in SI flow at lower pressure (see 1000 psia data), STP would recover very quickly, similar to the SNUPPS NOTRUMP results for the 2" break case.

In view of the SI flow increase, the recovery would actually be faster and core depression smaller for STP.

The active fuel would, therefore, remain covered at all time for a 1.5" or smaller LOCA for STP.

1.5" cold lea break with 50 F/hr cooldown This case was chosen for the long term cooling analysis to allow margin to the 100 F/hr limit allowed in the ERGS for cmall LOCA recovery.

As will be demonstrated, TREAT predicts that the loop seal in the broken loop clears several times starting after 5000 sec.

This time is consistent with the above discussion and estimate for the no cooldown case because as the RCS cools down and depressurizes, the difference between break flow and SI flow becomes smaller.

This extends the time to loop seal clearing.

With this background, the 1.5 inch break results for the 50 F/hr case is presented in the,following section.

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ATTACHMENT i ST HL-AE. /76 7 PAGEJo OF gg 4

3-1 1.5 Inch Diameter Cold Lea Break The analysis for this scenario is a variation and extension of the case analyzed for the TREAT /NOTRUMP comparison analysis (Ref. 1).

The time table of events is given in Table 3-1-1.

Plots of various parameters of interest are given in Figures 3-1-1 through 3-1-17.

The actions taken for this event follow the guidance given in the L.P. Rev. 1 ERGS (Ref. 4).

The following ERGS are exercised:

E-0, REACTOR TRIP OR SAFETY INJECTION E-1, LOSS OF REACTOR OR SECONDARY COOLANT ES-1.2, POST LOCA COOLDOWN AND DEPRESSURIZATION i

ES-1.3, TRANSFER TO COLD LEG RECIRCULATION i

l FR-P.1, RESPONSE TO IMMINENT PRESSURIZED THERMAL SHOCK i

CONDITION The ERG Integrity status tree orange priority implementation of FR-P.1 is taken after the accumulators start to inject into two loops with relatively low natural circulation flow.

Guideline FR-P.1 directs the operator back to ES-1.2 (following a one hour PTS soak) and ES-1.3 directs him back to ES-1.2 after switchover to cold leg recirculation is complete.

l The early portion of the transient was modeled consistent with the NOTRUMP evaluation model (see Ref. 1).

The over-temperature i

delta-T trip (at 10 sec) was defeated and constant 102% of full power operation was assumed until trip on low pressurizer pressure at 46 sec.

The safety injection actuation signal (SIAS) occurred approximately one second later.

Loss of offsite power and failure of emergency bus A were assumed coincident with reactor trip.

At that time, RCPs and pressurizer heaters tripped.

Steam dump to condenser was lost and SG PORV opening in the early portion of the transient was not assumed.

i Consequently, SG pressures increased to the lowest safety valve setpressure of 1200 psia.

A 60 sec delay (following SIAS) was also assumed for APW initiation to SG 2 and 3.

After RCS pressure dropped below 1500 paig (approximately 440 sec), the HHSI pump to loop 3 started to inject into the RCS (see Figs.

l 3-1-1 and 3-1-3).

The HHSI flow to the broken loop 2 was assumed to spill and there was no HMSI flow to loop 1 due to the limiting j

single failure.

Actions required in E-0 are very limited.

The first 14 steps are immediate actions to verify proper emergency automatic 4

operations.

The SI and AFW alignments are checked in Steps 15-18 followed by checks on RCP seal cooling (CCW flow) and RCS no-load temperature, Steps 19 and 20.

Cooldown to no-load was not assumed during the early portion of this transient since at 10-15 i

minutes, the temperatures were roughly 580 F, only slightly j

higher than no-load (567 F).

The cold leg temperature in loop 3 l

(Fig. 3-1-13) was also starting to decrease at this time due to i

addition of the cold (100 F) SI water.

19

ATTACHMENT I ST-HL-AE- 0 6 9 PAGE AI OF FG Subsequent steps in E-0 are for event diagnosis.

In Step 25, high containment radiation indications would cause transition to E-1.

Up to this point, no operator actions to control equipment were assumed.

The first such action taken was in E-1 Step 3, to control SG levels in the narrow range.

At this time in the transient, the AFW flow to SG 2 and 3 was reduced since level in these SGs was on the narrow range span (see Fig. 3-1-14 for SG 2 level).

No further actions were assumed in E-1, although a charging pump could have been started in Step 10 to provide additional makeup and RCP seal injection.

Since the RCS was at saturation, SI was not terminated (Step 11) and the operator remained in E-1 until transition to ES-1.2 in Step 18.

This transition was based on RCS pressure (approximately 1300 psia) higher than the shutoff head pressure of the low-head SI pumps.

The low-head SI pumps could also be stopped in E-1 (Step 14) due to high RCS pressure.

After transition to ES-1.2, credit was not taken for charging pump restart in Step 3.

Step 4 (check SG levels / control AFW flow) is the start of a cooldown to cold shutdown conditions.

This step is continuously checked during the recovery to ensure adequate AFW flow to the intact SGs.

Flow to two SGs was available based on the single failure assumed for this scenario.

Up to this step and before 1500 sec, the transient was almost identical to the case presented in Reference 1.

The only difference is a change in SI flows based on recent testing results (see Section 2-1).

In Step 5, a 50 F/hr cooldown was started at 1500 sec using the SG PORVs on the two active SGs (2 and 3).

The MSIVs on the steamlines were assumed to be closed by this time since this isolates the active SGs from the inactive SGs.

This could occur by the low-low Tcold (532 F) MSIV closure signal from the excessive cooldown protection system.

It is conservative to assume MSIV closure in the analysis since operator action is required to depressurize the inactive SGs.

A 50 F/hr cooldown rate was maintained in cold legs 1, 2 and 4 (Fig. 3-1-12).

However, due to the addition of cold SI water into loop 3 (Fig. 3-1-6), the cooldown in this loop exceeded 100 F/hr after 4000 sec.

Since the Integrity status tree FR-P.1 limit was not reached, the operators remained in ES-1.2 until directed to FR-P.1 later.

As the RCS continued to drain, the loop seal in the broken loop cleared several times between 5000 and 7000 sec.

When this occurred, RCS pressure dropped and recovered (Fig. 3-1-1) due to brief transitions to vapor break flow (Fig. 3-1-3).

The upper plenum level (Fig. 3-1-7) also dropped and recovered, however, the level remained above the top of the active fuel at all times (above 21.84 ft).

i l

20

ATTACHMENT l ST HL hE rW1 PAGE.tL OF f(,

At approximately 6200 sec, when RCS pressure was less than 600 psia, the accumulators in loops 1 and 3 began to inject into the RCS (loop 2 was assumed to spill).

The cold leg temperatures in these loops (Figs. 3-1-12 and 3-1-13) continued to decrease and the Integrity status tree orange priority FR-P.1 limit (242 F) was reached at 7000 sec based on the loop 3 cold leg.

The TREAT model does not consider the potential benefit of mixing between the cold leg, loop seal, and vessel downcomer.

If additional mixing similar to that found in the CREARE mixing test (discussed in Reference 10) was considered (i.e., the SI, pump suction, plus one-fourth downcomer node temperatures were averaged), a mixed temperature of 300 F was estimated.

Mcwever, the conservative approach was assumed and transition was made to FR-P.1.

This is conservative in the sense that FR-P.1 implementation delays the recovery.

The cooldown was stopped upon entry to FR-P.1 (Step 1).

Safety injection was not terminated (Step 5) since the core exit temperature was at saturation (Fig. 3-1-11).

A transition was then made to FR-P.1, Step 23 to complete a one hour PTS soak before returning to ES-1.2.

[Two conditions are required for SI termination in FR-P.1: 50 F subcooling plus errors (approximately 70 F total) plus vessel inventory above the top of the core.]

Before the cooldown was resumed, the inactive SGs (1 and 4) were depressurized to 600 psia (same as the active SGs).

The SG levels in 1 (and 4) dropped approximately 3 feet as a result of this depressurization (Fig. 3-1-14), however, these SGs did not dry out completely.

At 12000 sec, the cooldown using the active SGs was resumed at a rate less than 50 F/hr and cold leg subcooling greater than 200 F, as specified in FR-P.1.

At 12500 sec, the RWST depletion reached 350,000 gallons, and l

switchover to cold leg recirculation was initiated (ES-1.3).

The i

high-head SI recirculation was established at 220 F to simulate saturated sump water at 18 psia (or 3 psig).

The HHSI flow is not cooled in recirculation but fan coolers would limit the sump temperature for this size break to temperatures less than this.

There is no interruption of SI flow during switchover to recirculation.

At 15240 sec, the accumulators were isolated to prevent nitrogen injection into the RCS.

The isolation criterion used was hot leg temperature less than 420 F (for initial 1200 cubic-ft water volume).

Approximately 500 cubic-ft of water remained in each accumulator after they were isolated.

21

1 ATTACHMENT /

ST HL AE lM PAGEJ3 0F RG By 17000 sec, the upper head and upper plenum had refilled and pressurizer level was coming on span.

RCS subcooling based on core exit temperature was approaching 30 F (normal instrument uncertainty at low pressures).

By 20600 sec, the core exit temperature was less than 380 F (approximately 40 F below the saturation temperature ccrresponding to the shutoff head pressure of the low-head SI pump).

Consequently, the HHSI pump was stopped and the LHSI pump subsequently restarted to provide makeup.

At 20900 sec, the LHSI pump to loop 3 was restarted and minimum flow was verified.

Note in Figure 3-1-11 that the core exit temperature heated up after the NHSI pump was stopped.

This is due to reverse flow in the hotter inactive loops, in 4

l particular the pressurizar loop 4 (see Figs. 3-1-5 and 3-1-6 for hot leg flows and 3-1-8 for pressurizer level response).

Provided the inactive SG pressures are maintained close to the active SG pressures (within a few hundred psi) and the RCS is not rapidly depressurized, this heatup would be small.

The 380 F criterion for stopping the HHSI pump can be applied if one of the LHSI pumps can be operated to provide makeup.

The j

saturation temperature corresponding to the shutoff head pressure of the LHSI pumps is 420 F.

The criterion selected allows 20 F temperature error plus an additional 20 F margin for the potential heatup decribed above.

Following additional cooldown, RHR conditions were established by 24000 sec.

Pressurizer level (Fig. 3-1-8) was returning on span and SI flow slightly exceeded break flow (125 lbm/sec) at this time. A stable natural circulation flow was maintained in the core and loops 2 and 3 (Figs.

3-1-4, 3-1-5, and 3-1-6).

Boron concentration was more than adequate to allow additional cooldown to cold shutdown (greater than 2400 ppm).

Although RHR cut-in conditions have been demonstrated, the break /LHSI flow path will remove all the decay heat without the need for secondary heat sink or RHR System operation.

Based on a break flow equal to SI flow of 125 lbm/sec (Fig. 3-1-3 at 24000 sac) and a cold leg /LHSI enthalpy difference of 176 BTU /lbm (274-98), the break /LHSI path will remove 23 MWt.

However, if the RCS is assumed to heatup to 400 F (closer to saturation), the estimated heat removal capability will increase to 37 MWt.

These estimates also assume a high LHSI makeup temperature of 130 F, based on a high off-design CCW temperature of 120 F.

Normal CCW

]

temperature is 105 F and the corresponding LHSI makeup temperature would be at least 10 F lower.

i l

i i

l 22

ATTACHMENT I ST-HL AE-196')

PAGE Jg OF (fo The decay heat estimates for STP were calculated at various times after shutdown using 120% ANS-5-1971 (as assumed in the Appendix K analysis) and the revised standard ANS-5.1-1979 plus two-sigma (Ref. 7).

At the and of this analysis (24000 sec), the decay heat estimates are 43 MWt and 38 MWt, respectively.

Sensitivity to other times after shutdown is illustrated in the following table:

1979 ANS-5.1 (+2 sigma) 120% 1971 ANS-5 Time-sec Decay Heat Decav Heat 20000 (5.5 hr) 39 MWt 45 MWt i

40000 (11 hr) 33 MWt 38 MWt 80000 (22 hr) 28 MWt 32 MWt Based on the 37 MWt LHSI/ break energy removal capability estimate, supplemental RHR or AFW cooling would no longer be required at approximately 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months and 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , respectively, for the two decay heat estimates. The total AFST usage for this case is also comparatively low - less than 80,000 gallons at 24000 sec (7 hrs) or only about 18% of the 445,000 gallon available inventory.

The total amount of AFW used at 12 hrs is estimated to be less than 100,000 gallons.

Thus, the 1.5" break case is not a limiting one for depletion of the AFST.

A summary for this case is presented in Section 1, case 1.

1 l

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23 i

_ _ _. _ _ _. _ _. _ _ _,. _..__ _ _. _. _,. _ _ _ _.. _ _ _ _ _ _. _.. _., _ _ _ ~

ATTACHMENT')I ST-HL-AE I7/o FAGE d5 0F f6 Table 3-1-1 Time Table of Events 1.5 Inch Diameter Cold Leg Break Remarks /

Event Tiue (sec)

Tvoe of Action 1.5" Cold Leg Break on Loop 2 0

Initiating 102% Constant Power Operation 0-46 Event Reactor Trip, Loss of Offsite Power 46 Automatic AFW Injection at 120 F 106 Automatic (540 gpm to SG 2, 540 gpm to SG 3)

SI Starts Injecting to Cold Leg 3 440 Prcs < 1500 psi Control AFW to SG 2 and 3 When Req'd Continuous, as (E-1, Step 3 et. al.)

req'd to keep level in NR Start 50 F/hr Cooldown 1500 Using SG PORVs on SG 2 and 3 Loop Seal in Broken Loop Clears 5290 Caused by i

and Break Vents Vapor 5675 Continued RCS 6160 Draining 6930 Accumulators in Loops 1 and 3 6200 Automatic, Start to Inject 600 psia One Hour PTS Soak per FR*-P.1 7000-10600 Tcold < 242 F f

Depressurize Inactive SGs with PORVs 11120-11790 400 psi delta between SGs i

RWST Switchover (350,000 gallons used) 12500 Automatic I

High-head SI Temperature of 220 F (Psat(3 psig), no delay assured)

Isolate accumulators (Thot < 420 F) 15240 Prevent N2 Injection Depressurize Inactive SGs with PORVs 18530-18765 Stop HHSI to Allow LHSI (Thot < 380 F) 20600 SI Reduction Start one LHSI pump (Loop 3) 20900 l

24

ATTACHMENT /

ST HL AE- /761 PAGEJ6 OF96 Table 3-1-1 (Continued)

Time Table of Events 1.5 Inch Diameter Cold Leg Break Remarks /

Event Time (sec)

Tvoe of Action Continue Cooldown to < 350 F 21000-24000 RHR Cut-in Depressurize Inactive SGs with PORVs 21500-21705 End of Transient Modeled 24000 RHR Conditions Break /LHSI Flow Capable of Removing all Decay Heat:

AFST Depletion:

Based on ANS-5.1-1979 (+2 sigma) 24000 (7 hr) 80,000 gallons Based on 120% ANS-5-1971 43000 (12 hr) 100,000 gallons 25

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ATTACHMENT I ST-HL-AE 1767 PAGE 4v 0F fG 1

3-2 0.7 Inch Diameter Cold Lea Break The time table of events for this case is given in Table 3-2-1.

Plots of various parameters of interest are given in Figures 3-2-1 through 3-2-15.

Many of the actions taken for this case are the same as those used in the 1.5 inch break case.

During this 7 hr transient, the i

l E-0, E-1, and ES-1.2 ERGS were used.

The early response was also modeled similar to the previous The over-temperature delta-T trip (which would have caused case.

reactor trip at approximately 40 sec) was not modeled.

Reactor trip on low pressurizer pressure coincident with loss of offsite power occurred at 200 sec followed by SIAS about 2 sec later.

Loss of AFW to SG 2 and 3 was then started after a 60 sec delay.

the "A" diesel was also assumed as the limiting single failure.

RCP trip, pressurizer heater trip, and loss of steam dump to the condenser and through the SG PORVs were also assumed.

The SG 1300 pressures then increased to the safety valve setpressure, psia.

Transition from E-0 to E-1 and then ES-1.2 occurred in a manner similar to the previous analysis.

Cooldown to no-load (E-0, Step

-20) and charging pump restart (in E-1 or ES-1.2, Step 3), again were actions that normally would have been performed but were not performed in this analysis.

Ommission of the initial cooldown makes the analysis conservative from the standpoint of AFST depletion (longer cooldown required).

Operation of one charging i

pump would lower the subcooling requirement for stopping one (of two) HHSI pumps from 172 to 132 F.

Therefore, the recovery is effectively delayed by not operating the charging pumps.

The subcooling criteria for stopping the HHSI pumps (172 and 132 F) are based on the requirement that RCS subccoling is maintained greater than uncertainties after the pump is stopped.

Apart from the adjustment of AFW to control SG levels (first performed at 1000 sec), the first major operator action performed was the cooldown using the PORVs of SG 2 and 3 (started at 2200 sec).

This is approximately the same time that RCS pressure reached 1500 psig and the HHSI pumps started to inject into the (Figure 3-2-1 and 3-2-3).

The SGs without AFW (1 and 4)

RCS continued to relieve through their safety valves until they dried out several minutes later at 2400 sec (Fig. 3-2-13).

The flow in these loops also dropped (Figs. 3-2-6 and 3-2-7) and eventually stopped as the top of the U-tubes reached saturation and started to uncover (Fig. 3-2-9).

Earlier cooldown, faster cooldown, or establishing AFW to these SGs would have prevented this dry out.

However, this analysis demonstrates that it is possible to cooldown and depressurize to RHR cut-in conditions using two SGs.

43

ATTACHMENT J ST HL AE 1967 PAGE #50F PG By 7000 sec, RCS subcooling based on core exit temperature had reached 50 F (Figure 3-2-10).

Since normal subcooling uncertainty is only about 20 F, one pressurizer PORV could be opened to refill the pressurizer and regain control of RCS inventory.

Prior to this deliberate RCS depressurization, the inactive SGs were depressurized (7200-7550 sec) to prevent or minimize flashing in the inactive loops.

Between 8000 and 8060 sec, one pressurizer PORV was operated to restore pressurizer level above 21% (indicates heaters covered).

Due to the increase in SI flow and decrease in break flow during this action (and also the previous inactive SG depressurization),

the pressurizer, upper head, and inactive SG U-tube regions all refilled.

Pressurizer level continued to increase after the pressurizer PORV was shut since SI flow exceeded break flow.

Between 14000 and 14410 sec, the inactive SGs were again depressurized to approximately 250 psia, the same as the active SGs.

This depressurization was performed based on a 400 psi pressure difference between the inactive and active SG pressures.

l At 17000 sec, the 172 F criterion for stopping one of the i

high-head SI pumps was satisfied.

After this action was l

performed, RCS pressure dropped from 1300 psia to a new

" equilibrium" pressure of 1150 psia (Fig. 3-2-1).

Pressurizer level continued to increase without substantial change in RCS pressure because of condensation at the subcooled liquid-vapor interface in the pressurizer.

The pressurizer filled completely at approximately 18500 sec.

After continued cooldown, the second (last) high-head SI pump could be stopped, in this case based on the Thot = 380 F condition.

After this pump was stopped (at 19000 sec), RCS pressure dropped rapidly to 820 psia (Fig. 3-2-1) until the U-tubes in the inactive SGs and the pressurizer liquid reached saturation (520 F).

l In response to the decreasing pressurizer level, one pressurizer PORV was operated several times before the RCS depressurized enough for low-head safety injection to refill the RCS.

The temperature at the core exit remained subcooled during these periods.

There was, however, a heatup from 380 to approximately 410 F (Fig. 3-2-10) as the hotter fluid in the inactive loops mixed with the upper plenum and core exit water.

Temperature then decreased as the cooldown continued.

1 i

I 44

ATTACHMENT '

ST.HL Ad-19G 9 PAGE V6 0F 86 When the transient was stopped at 25500 sec, the core exit and hot leg temperatures were less than 350 F, RCS pressure was approximately 250 psia, and break flow was 27 lbm/sec.

Low-head SI flow had reached 100 lbm/sec and was decreasing at the end of the transient.

The SG U-tubes in the inactive loops were refilling (Fig. 3-2-9) due to this excess makeup flow.

Since all portions of the RCS were filled (or refilling), and the 350 psig

- 350 F cut-in conditions were satisfied, the RHR System could be placed in service in one of the loops to continue the cooldown to cold shutdown.

A low-head SI pump would be left operating in another loop to provide the required makeup.

At the end of this transient, the AFST depletion was 133,500 gallons or 30% of the minimum usable inventory.

The RWST depletion was 168,000 gallons.

This is less than 50% of the switchover volume and less than 40% of the total usable RWST volume.

It should be noted that the makeup flow = break flow requirement (27 lbm/sec) is within the capacity of one of the centrifugal charging pumps.

Thus, charging flow could be used in place of low-head SI makeup.

A summary for this case is provided in Section 1, Case 2.

l r

45

ATTACHMENT 8 ST-HL AE-l?G9 PAGE 49 OF fG Table 3-2-1 Time Table of Events 0.7 Inch Diameter Cold Leg Break Remarks /

i Event Time (sec)

TvDe of Action 0.7" CL Break, Loop 2 0

Initiating 102% Constant Power Operation 0-200 Event Reactor Trip, Loss of Offsite Power 200 Automatic AFW Injection at 120 F 260 Automatic (540 gpm to SG 2, 540 gpm to SG 3)

Control AFW to SG 2 and 3 When Req'd Continuous, as (E-1, Step 3 et. al.)

req'd to keep level in NR SI Starts Injecting to CL 2 and 3 2200 Prcs < 1500 psi Start 50 F/hr Cooldown 2200 Using SG PORVs on SG 2 and 3 Inactive SGs 1 and 4 Dry Out 2400 Dump Stean from Inactive SGs 1 & 4 7200-7550 Req'd prior Uring SG PORVs to RCS Depress l

Open One Pressurizer PORV 8000-8060 l

to Restore Level Depressurize Inactive SGs 1 and 4 14000-14410 400 psi delta Stop one HHSI Pump - Loop 2 (Based on 172 F subcooling) 17000 Stop last HHSI Pump to Allow LHSI 19000 (Based on Thot < 380 F)

Open One Pressurizer PORV 21800-21940 to Restore Level with Subcooling 22700-23100 and Level Indicated 24500-24600 LHSI to Loop 3 Starts to Inject 22900 Automatic End of Transient Modeled 25500 (RHR Conditions Established) l 46

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ATTACHMENT /

ST.HL AE-1767 PAGE G3 0F86 3-3 Feedline Break Appendix K modeling assumptions and initial conditions identical to those used in the small LOCA analyses were used in the TREAT feedline break analysis.

The actions taken for recovery from the feedline break follow the guidance given in the following ERGS:

E-0, REACTOR TRIP OR SAFETY INJECTION E-2, FAULTED STEAM GENERATOR ISOLATION E-1, LOSS OF REACTOR OR SECONDARY COOLANT ES-1.1, SI TERMINATION ES-0.2, NATURAL CIRCULATION COOLDOWN Since normal letdown is not safety grade, the reactor vessel head 4

vent is used.

The operator would be directed to implement the STP specific guideline ES-0.5, NATURAL CIRCULATION WITHOUT LETDOWN, via transition from ES-0.2.

Since pressure is difficult to maintain without pressurizer heaters (not safety grade), the pressure - hot leg temperature limits are redefined to limit upper head voiding at the 25 F/hr cooldown limit for an upper head Thot plant.

The STP specific cooldown limit curve developed for this purpose is given in Figure 3-3-1.

As noted in the feedline break analysis of FSAR Section 15.2.8 i

I (Ref. 3) and the summary of equipment of Table 2-1, the AFW to one SG is assumed to spill.

In this analysis, SG 1 is assumed to be the faulted SG.

Feed flow to only one SG (in this case SG 2) is available for most of the hot standby period until a

cross-connect to another SG (SG 3) can be opened.

Two SGs are i

eventually needed for the cooldown due to the limited capacity of

{

the SG PORVs at low temperatures and pressures (68,000 lbm/hr at 100 psia).

Required operator actions during the early portion of this transient are summarized in FSAR Table Q211.52-2.

These actions include isolation of AFW to the faulted SG (performed in E-2) and stabilization of RCS temperature to no-load Tavg using the SG i

PORV on the single intact SG receiving AFW (performed in ES-1.1 Step 14).

These critical actions are performed at 30 and 40 minutes, respectively.

This 30 minute delay is long compared to the expected time required to complete the immediate actions in E-0, diagnose the accident, and isolate the faulted SG in E-2.

Since faulted SG isolation is the first safety grade operator 4

action, a shorter time (20 minutes) would be allowed for this '

l Condition 4 accident based on Reference 8.

62 l

ATTACHMENT I ST-HL-AE- / M PAGE 64 0F f6 It should be emphasized that the TREAT analysis presented is intended to be consistent with but not necessarily identical to the LOFTRAN FSAR feedline break analysis.

The heatup rate and maximum temperature (approximately 640 F) from the TREAT analysis c

agree closely with the FSAR.

The " Appendix K" decay heat assumed in TREAT (120% ANS-5, 1971) is higher and more conservative

-These features plus the limiting 25 F/hr cooldown rate assumed make this analysis conservative with respect to AFST depletion, one of the key parameters of interest for this scenario.

The time table of events for this 21 hr transient is presented in Table 3-3-1 and transient plots of interest are given in Figures 3-3-2 through 3-3-16.

The early portion of the accident is a secondary depressurization or cooldown during which time RCS pressure (Figure 3-3-2), SG pressures (Figures 3-3-3 and 3-3-4), pressurizer level (Figure 3-3-5), and temperatures (Figures 3-3-6 and 3-3-7) all decrease.

After the MSIVs close (automatic signal at 560 sec), the faulted SG (Figure 3-3-3) rapidly blows down and the event quickly turns into a heatup event.

The pressures in the SGs without AFW (SG 3 and 4) increase to the safety valve setpressure (at approximately 1

1500 sec) and these SGs subsequently dry-out minutes later.

The heatup causes the pressurizer safety valves to cycle until after the SG PORV on the SG with AFW flow (SG 2) is opened at 2400 sec.

In this scenario, however, the conditions for SI termination must be achieved (in E-1) before the SG PORV is i

opened (in ES-1.1).

The four criteria for SI termination can be shown to be satisfied :

1. RCS Subcooling Greater Than Uncertainties l

2.

Secondary Heat Sink Available RCS Pressure Greater Than the Shutoff Head Pressure of the 3.

l High-head SI Pumps 1

4. Pressurizer Level on Span Actual subcooling is approximately 50 F during the heatup and pressurization (greater than normal or adverse containment errors).

SG 2 (with AFW flow) satisfies the second criterion and the third and fourth criteria are clearly satisfied.

Therefore, the transition to ES-1.1 is justified.

After the initial opening, the SG PORV is then controlled (manually or with the controller) to maintain pressure at approximately 900 psia and reduce the core exit temperature from approximately 640 F to less than 615 F.

Since three of the SGs are dried out, the hot leg and cold leg temperatures in these loops are approximately the same as the core exit temperature.

Essentially all of the primary to secondary heat transfer occurs in loop 2 where Tcold is maintained near 535 F (loop average temperature of approximately 575 F).

This supports the 80 F natural circulation delta-T required for decay heat removal using only one loop.

In the ERGS, the operator would be instructed to stabilize hot leg temperatures (ES-1.1, Step 14).

The operators 63

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l PAGE 650F fG are instructed per the STP EOPs to control RCS temperatures to no-load Tavg (567 F), so the temperatures maintained in this l

analysis are conservatively high in comparison to what would be expected.

At 3000 sec, one charging pump is restarted to provide RCP seal flow.

This pump was not considered operational prior to reactor trip and would have been stripped upon loss of offsite power plus SIAS.

Low pressurizar pressure SIAS may have been avoided if '

charging pump (s) were operating, but SIAS on low steamline pressure would still occur.

Thus, early operation of the charging pump (s) would have a negligible effect.

The delay taken for charging pump restart allows adequate time for local operator action, if required.

Earlier action to provide charging for seal injection would be expected.

The charging pump was considered aligned to one BAT with a minimum concentration of 7000 ppm boron.

Mest of the RCS boration during the hot standby period was accomplished with seal injection.

A small amount of charging i

flow was used between 3600-5000 and 11000-11500 see to increase RCS subcooling.

Figure 3-3-11 shows the normal charging flow and net RCS makeup through one (of four) seal injection paths.

The reactor vessel head vent was operated during the hot standby period to limit the RCS pressure rise (Figure 3-3-12).

Since pressurizer level increased to over 95% during the initial heatup and heaters were not assumed operable, it was not possible to decrease pressurizer level to indicate less than 100% using the head vent, without subsequent loss of RCS subcooling (note periods of head vent operation in Figure 3-3-6).

A small steam bubble, however, was maintained in the pressurizer throughout the transient.

Because of the small size of this steam bubble, RCS pressure was sensitive to slight changes in makeup and head vent flow.

Pressure was controllable for this limitina scenario within a band of several hundred psi (Figure 3-3-2).

Smoother control of charging flow than illustrated in Figure 3-3-11 plus earlier initial cooldown (at lower pressurizer level) would l

result in a pressure transient without these fluctuations.

At.10800 sec and during the last hour of hot standby, i

cross-connects were opened to supply AFW to a second SG (SG 3).

The operator would normally be instructed to establish AFW slowly to a dried-out SG.

For recovery from this Condition 4 event, however, this precaution was not taken.

As level was restored in this SG (Figure 3-3-13), operation of the SG 2 PORV could be delayed as heat transfer was established with the other SG.

Both SG PORVs were then operated to maintain SG pressures at approximately 1200 psia (Thot = 610 F) for the duration of the four hour hot standby period.

I l

64 I

ATTACHMENT /

ST-HL-AE- /?6 7 PAGE GG OF g6 At 14560 sec, a cooldown was started using the PORVs of SG 2 and 3.

Charging flow was adjusted a number of timec during the cooldown to makeup for cooldown shrink, maintain RCS pressure, and provide additional boration.

At 33000 sec, approximately 18000 gallons of the BAT had been depleted (less than the Tech Spec required minimum), so the charging pump was realigned to the RWST (2500 ppm) for the duration of the transient.

By this time, the boron concentration increase (Figure 3-3-14) was more than 1200 ppm.

This increase is approximately double that required (for more limiting EOL conditions) to maintain adequate shutdown margin at cold shutdown Xenon-free conditions.

Thus, there is no suberiticality concern in this scenario.

As per guidance in ES-0.5, this cooldown rate was limited to less than 25 F/hr to avoid upper head voiding.

This rate applies to plants with upper head temperatures initially equal to the hot leg tempernture, Thot.

Since South Texas is not a 100% Thot plant (the full power steady state upper head flow is high enough to make it a "70%" Thot plant), the upper head soak time required for the upper head to cool prior to depressurization to RHR l

cut-in pressure (350 psig) could be eliminated.

The analysis demonstrated that if a 25 F/hr cooldown rate is maintained, no soak time is required.

The transient was continued until 65000 sec (18 hrs) until the head vent was opened to depressurize the RCS (65000-66100 sec).

During the end portion of the transient, temperatures changed very little because of the limited SG PORV capacity.

Finally, at 75600 sec (21 hrs), the transient was terminated.

At this time, RCS temperatures and pressure were stabilized at 350 psig, Thot l

was less than 360 F, and Tcold in the active loops was l

approximately 310 F.

Although Thot of 350 F is the usual target, l

the RHR system could be placed in service with Thot as high as 380 F and still satisfy minimum subcooling requirements.

If less l

restrictive decay heat assumptions were used, it would be l

possible to achieve Thot less than or equal to 350 F.

Based on ANS-5.1-1979, the decay heat at the end of this transient would be approximately 28 MWt (see Section 3-1).

The cold leg temperatures in the active loops would then be 300 F and the corresponding Thot would be less than 350 F by 18 hours2.083333e-4 days 0.005 hours 2.97619e-5 weeks 6.849e-6 months .

Thus, RHR cut-in conditions can be achieved.

65

ATTACHMENT I ST HL-AE /%7 PAGE 610F g6 During this transient, the depletions from the AFST were as follows:

Initial spill, 675 gpm for 30 minutes:

20,300 gallons Four hours at hot standby:

104,400 gallons Fourteen hours Cooldown:

217,300 gallons Three hours depressurize to RHR 54,300 gallons and stabilize:

Twenty-one hour Total:

396,300 gallons Based on a usable AFST volume of 445,000 gallons, there is a margin of 48,700 gallons at 21 hrs.

An AFW flow of 205 gpm was required at this time to match the decay heat of 32.5 MWt (Figure 3-3-15).

This allows approximately four more hours before AFST depletion, i.e.,

25 hrs total.

The AFW flow requirement at 21 hrs for the ANS-5.1-1979 case is approximately 175 gpm and the corresponding steam flow required (flow from one PORV = 44,000 lbm/hr) would be achievable at 70 psia or slightly below. The AFST depletions would also be approximately 15% less, leaving a margin of more than 100,000 gallons at 21 hrs.

A summary for this case is provided in Section 1, Case 3.

I 66

ATTACHMENT I ST HL AE- /% 7 PAGE GkOFFG 4

Table 3-3-1 Time Table of Events Feedline Break f

Remarks /

Event Time (sec)

Tyne of Action Feedline Break, SG No. 1 10 FSAR Low-low SG Level Reactor Trip with 30 FSAR-automatic Loss of Offsite Power AFW Delivery - 540 gpm to SG 2 90 FSAR-automatic 675 gpm spill from SG 1 MSIVs Close on Low SL Pressure SI 560 FSAR-automatic SG 3 and 4 Pressures Reach Safety 1500 automatic Valve Setpoint Pressurizer Safety Valves Cycle 1850 automatic Valves Cycle Isolate AFW to SG 1 (E-2, Step 4) 1890 Req'd Op. Act.

per Q211.52-2 Control AFW to SG 2 When Req'd Continuous, as (E-1, Step 3 et. al.)

req'd to keep level in NR SI Termination (E-1 to FS-1.1) 2200 Stabilize Thot with SG 2 PORV 2400 Req'd Op. Act.

(dump to 900 psia, ES-1.1, Step 14) per Q211.52-2 Establish RCP Seal Flow with 3000 Req'd Op. Act.

Charging (align to BAT) for c.d. and boration Control Charging to Control 3600-5000 Req'd for Min.

RCS Pressure Subcooling Operate RV Head Vent to 5060-7310 Control RCS Pressure 9300-10640 11870-14600 67

ATTACHMENT /

ST-HL AE-1961 PAGE 69 0F66 Table 3-3-1 (Continued)

Time Table of Events Feedline Break Remarks /

Event Time (sec)

Tvoe of Action Complete AFW Cross-Connect to SG 3 10800 Req'd Op. Act.

(per E-1 or ES-1.1) do before c.d.

End of Hot Standby 14400 4 hrs Start 25 F/hr cooldown using 14560 Req'd Op. Act.

SG 2 and 3 PORVs Finite AFST Operate Charging for Makeup 16860-end Req'd Op. Act.

and Boration Switch Makeup Supply to RWST 33000 Use T.S.

limit of one BAT End of Cooldown, Depressurize 65000-66100 Depress. to RCS Using RV Head Vent RHR cut-in.

End of Transient 75600 RCS Stabilized RHR Conditions l

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l Section 4 References l

1. Frantz, E.

R.,

P. H. Huang, and R. P. Ofstun, Comoarison of the TREAT and NOTRUMP Small Break LOCA Transient Results, WCAP-11297, Westinghouse Non-Proprietary Class 3, September 1986.

2. Rupprecht, S.D.,

R.A. Osterrieder, M.E. Wills, and J.M.

Willis, Westinahouse Small Break LOCA ECCS Evaluation Model Generic Study with the NOTRUMP Coda, submitted for NRC review, June 1986 (Class 3 version of this WCAP to be provided later).

3. "Feedwater System Pipe Break," South Texas FSAR Section 15.2.8, March 1986 draft ammendment.

4. Westinghouse Owners Group Emergency Response Guidelines, Low-pressure Rev.

1, September 1, 1983.

5. Proposed ANS Standard, " Decay Energy Release Rates Following Shutdown of Uranium-Fueled Thermal Reactors," ANS-5, 1971, Revised October 1973.

6. Branch Technical Position ASB 9-2, " Residual Decay Energy for Light-Water Reactors for Long Term Cooling," Rev.

2, July 1981.

7. American National Standard " Decay Heat Power in Light Water Reactors,", ANSI /ANS-5.1-1979.

8. American National Standard " Time Response Design Criteria for l

Nuclear Safety Related Operator Actions," ANSI /ANS-58.8, September 14, 1984.

i

9. Meyer, C.E.,

Emercency Response Guidelines Validation Procram Final Report, WCAP-10599, Westinghouse Non-Proprietary Class 3, June 1984.

4

10. Cheung, A.

C.,

et. al., A Generic Assessment of Sionificant Flaw Extension. Includina Staanant Looo Conditions. From Pressurizer Thermal Shock of Reactor Vessels on Westinchouse Nuclear Power Plants, WCAP-10319, Westinghouse Non-Proprietary i

l Class 3, December 1983.

l 85

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