ML20065E212

Proposed Tech Specs Re Surveillance,Reactor Protection Monitoring Sys,Jet Pump Surveillance,Organization & Steam Line Area Temp Switch Deviation

ML20065E212
Person / Time
Site:	Monticello
Issue date:	09/24/1982
From:	NORTHERN STATES POWER CO.
To:
Shared Package
ML112970873	List: ML20065E212
References
NUDOCS 8210010046
Download: ML20065E212 (60)

Text

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EXEIBIT B License Amendment Request Dated September 24, 1982 Exhibit B, attached, consists of the following revised pages for the Appendix A Technical Specifications which incorporate the proposed l changss. l Pages l 1

vi 4

25a (new page) 27 48 50 60 62 69  !

70 l 71  !

90 128 129 130s 131 132 132a 153 164 165 166 171 172 175 180 203 204 227c l 230 233 234 235 238 239 240 241 244 244a (new page) 245 l

l 8210010046 820924 I

PDR ADOCK 05000263 P PDR

TABLE OF CDNTENTS Page 1.0 DEFINITIONS 1 2.0 SAFETY LIMITS AND LIMIIING SAFETY SYSTEM SETTINGS 6 j

- 2.1 and 2.3 Fuel Madding Integrity 6 2.1 Bases 10 2.3 Bases 14 2.2 and 2.4 Reactor Coolant System 21 2.2 Bases 22 2.4 asses 24 3.0 LIMITING CONDITIONS FOR OPERATION AND 4.0 SURVrTTTaur*F REQUTRmnrIS 25a 4.0 Surveillance Requirements 25a 3.1 and 4.1 Beactor Protection System 26 3.1 Bases 35 4.1 Bases 41 3.2 and 4.2 Protective Instrumentation 45 A. Primary Containment Isolation Functions 45

5. Emergency Core Cooling Subsystems Actuation 46 C. Control Rod Block Actuation 46 D. Air Ejector Off-Gas System 46 E. Reactor Building Ventilation Isolation and 48 Standby Gas Treatment System Initiation F. Racirculation Pump Trip and. Alternate Rod 48 Injection Initiation 3.2 Bases 64 4.2 Bases 72 3.3 and 4.3 Control Bad System 76 A. Reactivity Limitations 76 R. Control Rod Witindrawal 77 C. Scram Insertion Times 81 i

D. Control Rod Accumulators '

82 l E. Reactivity Anomalies 83 F. Required Action 83 3.3 and 4.3 Bases 84 i REY

i l

o LIST OF TABLES Table No. Page 3.1.1 Reactor Protection System '(Scram) Instrument Requiremments 28

( 4.1.1 Scram Instrument Functional Tests - Minimum Functional Test Frequencies for Safety Instrumentation and Control Circuits 32 4.1.2 Scram Instrumenc Calibration - Minimum Calibration i Frequencies for Reactor Protection Instrument Channels 34 l 3.2.1 Instrumentation that Initiates Primary Containment Isolation Functions 49 3.2.2 Instrumentation that Initiates Emergency Core Cooling Systems 52 l

l 3.2.3. Instrumentation that Initiates Rod Block 57 3.2.4 Instrumentation that Initiates Reactor Building i

Ventilation Isolation and Standby Gas Treatment System Initiation 59 3.2.5 Instrumentation that Initiates a Recirculation Pump Trip and Alternate Rod Injection 60 3.2.6 Instrumentation for Safeguards Bus Degraded 60s Voltage and Loss of Voltage Protection

{ 3.2.7 Trip Functions and Deviations 70 4.2,1 Minimum Test and Calibration Frequency for Core Cooling, 61 Rod Block and Isolation Insertamentation 3.6.1 Safety Related Snubbers 131 3.13.1 Safety Related Fire Detection Instruments 227c 3.7.1 Primary Containment Isolation 172 4.8.1 Monticello Nuclear Plant - Environmental Monitoring Program Sample Collection and Analysis 193 3.11.1 Maximuu Average Planar Linear Heat Generation Race vs. Exposure 214 3.14.1 Instrumentation for Accident Monitoring 229b 4.14.1 Minimum Test and Calibration Frequency for Accident Monitoring Instrumeatation 229c 6.1.1 Minimum Shift Crew composition 236 vi REV

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4. Protective Function - A system protective action which results from the protective action of the channels monitoring a particular plant condition.

R.

Rated Heutron Flux - Rated flux is the neutron flux that corresponds to a stesay-state power level of 1570 thermal megawatts.

S.

Rated Thermal Power - Rated thermal power means a steady-state power level of 1670 thermal megawatts.

T. Reactor Coolant System Pressure or Reactor Vessel Pressure - Unless otherwise indicated, reactor vessel pressures listed in the Technical Specifications are those existing in the vessel steam space.

U.

Refueling Operation and Refugling Outage - Refueling Operation is any operation when the reactor water temperature is less than 212"F and movement of fuel or core components is in progress. For the purpose of designating frequency of testing and surveillance, a refueling outage shall mean a' regularly scheduled refueling outage; however, where such outages occur within 8 months of the completion of-the previous refueling outage, the required surveillance testing need not be performed until the next regularly scheduled outage. -

V.

Safety Limit - The safety limits are limits below which the maintenance of the cladding and primary system integrity are assured. Exceeding such a limit is cause for plant shutdown and review by the Commission before resumption. of plant operation. Operation beyond such a limit may not in itself result in serious consequences but it indicates an operational deficiency subject to regulatory review.

W.

Secondary Containment Integrity - Secondary Containment Integrity means that the reactor building.is closed and the following conditions are met:

1. At least one door in each access opening,is closed.

2. The standby gas treatment system is operable.

3. All reactor building ventilation system automatic isolation valves are operable or are secured in the closed position.

X.

Sensor Check - A qualitative determination of operability by observation of sensor behavior during oreration.

This determination shall include, where possible, comparison with other independent sensors measuring the same variable, 1.0 REV

3.0 LIMITING CONDITIONS FOR OPERATION 4.0 SURVEILIANCE REQUIREMENTS 4.0 SURVEILIANCE REQUIREMENTS A. The surveillance requirements of this section shall be met. Each surveillance requirement shall be performed at the specified times except as allowed in l

i B and C below.

B. Specific time intervals between tests may be adjusted plus or minus 257. to accomodate i normal test schedules with the exception that, the intervals between tests scheduled for refueling shutdowns shall not exceed two years.

! C. Whenever the plant condition is such that a system or component is not required to be operable the surveillance testing associated with that system or component may be dis-continued. Discontinued surveillance tests shall be resumed less than one test interval before establishing plant conditions requiring operability of the associated system or component, unless such testing is not Practicable (e. g. APRM and IRM heat balance calibration cannot be done prior to reaching power operation) in which case the testing will be resumed within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of attaining the plant condition which permits testing to be accomplished.

- i 3.0/4.0 25a REV

3.0 LIMITING CONDITIONS FOR OPERATION 4.0 SURVEILIANCE REQUIREMENTS ,

5. Upon discovery that the requirements for the B. Once per day during power operation the number of operable or operating trip systems MFLPD (Meximum Fraction of Limiting or instrument channels are not satisfied, Power Density) shall be checked and the act ion shall be initiated to: scram setting given by the equation in~

Specification 2.3.A shall be adjusted if

1. Satisfy the minimum requirements by necessary.

placing appropriate devices, channels, or trip systems in the tripped condition, or

2. Place and maintain the plant under the specified required conditions using normal operating procedures C. RPS Power Nonitoring System C. RPS Power Monitoring System

1. Except as specified below, both channels 1. Instrument Functional Tests of of the power monitoring system for the each RPS power monitoring channel HG set or alternate source supplying shall be performed at least once each reactor protection system bus every six months.

shall be operable with the following setpoints: 2. At least once each Operating Cycle an Instrument Calibration of each

m. Over-voltage -

$128 VAC RPS power monitoring channel shall

b. Under-voltage -

2104 VAC be performed to verify over-voltage,

c. Under-frequency -

257 RZ under-voltage, and under-frequency setpoints.

2. With one RPS electric power monitoring channels for the MG set or alternate source supplying each reactor protection system bus inoperable, restore the inoperable channel to Operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or remove the associated RPS HG set or alternate power supply from service.

i

3. With both RPS electric power monitoring channels for the MG set or alternate source supplying each reactor protection system bus inoperable, restore at least one to Operable status within -

30 minutes or reaove the associated RPS HG set or alternate power supply from se,rvice.

3.1/4.1 27 REV

i r .

b 3.0 LIMITING CONDITIONS FOR OPERATION 4.0 SURVEILIANCE REQUIREHENTS i

E. Reactor Butiding Ventitation Isolation ,

and Standby Ces Treatment System Initiation .

1. a. Except as specified in 3.2.E.1.b .

below, four radiation monitora shat! ,

l be operable at,att times..

b. One of the two monitors in the venti-1stion plenum and one of the two radia- .

i tion monitors on the refueling floor may be inoperable for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. If the inoperable monitors are not restored to service in this time, the reactor build-ing venttistion system shall be iso- 4 1sted and the standby gas treatment i system operated untti repairs are' j complete.

2. The radiation monitora shall be set to trip as follows:

(a) venttiation plenum h 3 mr/hr '

i .

(b) refueling floor 6100 ar/hr

! 3. When irradiated fuel is in the reactor vessel and the reactor water temperature is above

• 212'F. the limiting conditions for operation ,

for the instrumentation listed in Table 3.2.4 shall be met. -

F. Recirculation Pump Trip and Alternate Rod Injection Initiation j

j 1. Whenever the reactor is in the RUN Mode, the

limiting' conditions for operation for the j instrumentation listed in Table 3.2.5 shall

~

] be met. .

1 48 3.2/4.2 REV

TABLE 3.2.1 - Continued

• I Him. No. of Operable Total No. of Instru - or Operating Instru-ment Channels Per ment Channels Per Trip , Required

, Function Trip Settings Trip System System (1,2) Conditions

! b. High Drywell Pressure *

(5) i2psig 2 2 D

! 3. Reactor Cleanup System j (Croup 3) 1

a. Low Re' actor Water > 10'6" above Level the top of the active fuel 2 2 E

b. liigh Drywell Pressure i2peig 2 2 E

4. IIPCI Steam Lines

a. IIPCI Higli Steam Flow 1150,000 lb/hr 2(4) 2 F with 160 second

time delay

b. IPCI liigh Steam Flow 1300,000lb/hr 2(4) $ F

c. IIPCI. Steam Line 1200 F 16(4) '6 F Area High Temp.

i

5. RCIC Steam Lines

a. RCIC liigh Steam Flow 145,000 lb/hr 2(4) 2 ,

C

b. RCIC Steam Line firea 1200 F 16(4) 16 C 1

6. Shutdown Cooling Supply Isolation

a. Reactor. Pressure s75 psig 2(4) 2 c Interlock at pump suction 1

50 3.2/4.2 REV

l 3

Table 3.2.5 Instrumentation that Initiates a Recirculation Pump Trip and Alternate Rod Injection e

{ Hinimum No. of Oper-tfinistas No. of able or Operating

• operable or Total No. of Instru- Instrument Channels Required

! Operating Trip ment channels Per Per Trip, System conditions

• 1 Function Trip Settina Systems (1) Trip System (1)

1. High Resctor Dome .

Pretoure i 1150 psig 2 2 2 A

2. Low Reactor Water 1.evel 36' 6" above the ,

top of the 3

active fuel. 2 2 2 A i

i NOTE:

i

1. Upon discovery that minimum requirements for the number of operable or operating trip systems or instrument channels are not satisfied, action shall be initiated to

a. Satisfy the requirements by placing the appropriate channels or systems in the tripped c6ndition, or

b. Place the plant under the specified required condition using normal operating procedures.

• Required conditic...e when ministas conditions for operation are not satisfied:

l A. Reactor in Startup, Refuel or Shutdown mode. ,

l s

, 60 l 1.2/4.2 REV

l l -

i Table 4.2.l - Coatlawed ,

Himleine Test and callbretlois frequency For Core Coellas 3-Bad Block anJ leolation lastreisentatloa  ;

I.ast rinnent Diannel Test (3) Calibretion (3) Sensor nieck ,(3) i .

l

3. Stese I.Ina Low Pressure liete i Once/3 months IIone

4. Gavae I.las 111:16 ReJletlon once/ week (5) leote 4 Once/ shift i

- NPCI IS08.Afl0N

1. St ees B.Ine liigle I'luw Once/ month Ones/3 seethe 11one

2. Stees I.ine High Teal.oretute Once/ month ones/3 monthe None 1

SCIC IS01.Afl0N f I. Slese Line Migli Flow Once/ month Dece/3 monthe None j 2. St ees I.lpe Nigh Temperature hte l Once/3 sooths Ilone i .

j sEACTOR bHII.DlHO VENTIAl.T g I * .

l l. DeJletlon Hamitors (Flanus) Note i Onse/3 months Once/ shift j 2. B.JIstion llanitors (Refueling Floor) Note i Once/3 months (4) ,

OFF-CAS ISOLATION 1

l 1. Sadletion Hontiere (Alt Ejectore) Notes (1,$) Note 4 Once/ shift NECINCul.ATION FHHP TRif

l. Beactor Illah Pressure Note i Once/Operstlag cycle- once/ Day Tressaltter

, once/3 m atko-Talp Unit

2. Lector low Waar f.evel (llate 3) Once/ month once/operstles Cycle- Once/ shift 4

Traneelster Once/3 Heathe-Trip thilt I

SHUTDOWN COOLING SUPPLY IS01ATION

1. Reactor Pressure Interlock Note 1 Once/3 months None 4

I 3.2/4.2 hy

Bases continued:

increases core voiding, a negative reactivity feedback. High pressure sensors initiate the pump i

trip in the event of an isolation transtant. Low level sensors initiate the trip on loss of feed-water (and the resulting MSIV closure). The recirculation pump trip is only required at high reactor power levels, where the safety / relief valves have insufficient capacity to relieve the steam which continues to be generated af ter, reactor isolation in this unlikely postulated event, requiring the trip to be operable only when in the RUN mode is therefore. conservative.

The ATWS high reactor pressure and low water level logic also initiates the Alternate Rod Injection syst'm.

e Two solenoid valves are installed in the scram air header upstream of the hydraulic control units. Each of the two trip systema energizes a valve to vent the header and causes rod insertion. This greatly reduces the long tenn consequences of an ATWS event.

• Although the operator will set the set points within the trip settings specified in Tables 3.2.1, 3.2.2, 3.2.3, 3.2.4, 3.2.5, and 3,2.6, the actual values of the various l set points can differ appreciably from.the value the operator is attempting to set. The deviations could be caused by inherent instrument error, operator setting error, drift of the set po' int, ect. Therefore, these deviations have been accounted for in the various transient analyses and the actual trip settings may vary by the following amounts.

I i

69 3.2 BASES REV

- Table 3.2,7 Trip Functions And Deviations Trip Function Deviation l Reactor kilding Ventilation Isolation ar.d ,. Ventilation P1emas . +0.2Mr/Hr l Standby Oas Treatment System Initiation Badiation Monitors l Specification 3 2.E.3 and 'Ihble 3 2.3 6 Refueling D oor Radiation Monitors +5 Mr/Br I Iow Beactor Water level 6 inches Righ Drywell Pressure + 1. poi Primary Contairunent Isolation Functions Iow Iow Water level -3 inches -

i Table 3 2.1 High now in Main Steam Line +2%

! High Temp. in Main Steam +1dOF i I&ne Tunnel l

i Iow Presrure in Main Steam -10 pai l IAne High Drywell Pressure +1 pai i

f Iow Beactor Water level -6 inches j HPCI High Steam now +7,500 lb/hr HPCI Steam IAne Area High +2 F

'nssp.

DCIC High Steam now +2250lb/hr BCIC Steam line Area High Temp +2*F Shutdown Cooling Supply Iso +25 pai 3.2 BASES 70-

. REV

b d

Table 3.2.7 - continued '

Trip Function and Deviations Trip Function Davistfos leistrumentation That Initiates Emergency I.ow-1.ow Ruactor Water Level -3 laches-curu Couting Systems Tablu 3.2.2 Ileactor Low Pressure (rump -10 pel Start) Paraissive High Drywell Pressure ,

el pet I.ow Reactor Pressure (Valve -10 pet Fermissive)

Instrumentation That Initiates IRH Downscale -2/125 of Scale Rail Bluck IMH Upecale +2/125 of scale Table 3.2.3

'APRH Downscale -2/125 of scale april lipocale See Basie 2.3 NAH pownscale -2/125 of Scale RIPI Upacala Sumo as AFRH Upscale 4

Scram Discharge Volume-High

• I gallon l.evel Instrumentation That Initiates liigli Reactor Freasure + 12 pel Recirculattun Pump Trip and Low Reactor Water Level -3 Inches Alternate Rod In_iection A violation of this specification is assumed to cccur only when a device le knowingly set outelde of the limiting trip settings, or, when a silffletent number of devices have been affected by any means such that

the autossatic function is Incapable of operating within the allowable deviation while in a reactor mode in wlitch the specified function anist be operable or whose actions specified are act initiated as specified.

l I

I 3.2 IIASES 71 "EY l

I

~

f I

liases continued 3.3 and 4.3: .

1he analysis assumes 50 milliseconds for iteactor Protect ion System delay, 200 milli seconds f rona de-energiz.at ion of scra.e solenoids to the beginning of rod motion, and 175 milliseconds later the rods are at the 51 position.

Section 3.3.C.3 ellows a lower HCPg limit to be used if the cycle average scram time (T3 % ) is less than the

adjusted analysis mean scram t ime ("Is ) (see lieference 7, of Section 3.!!) ,

I  %.. is the weighted cycle average scram t ime to the 20I Insertion position (~ notch 38) of all the operal,le rods asessured at any point in the cycle.

i

! where: n = the number of surveillance testa performed

" to date in this cycle.

(_. HTg 1 N i = number of control rode measured in the I"I T3,, = ith test.

T = average scram time to the 20% insert ion H i position of all rade measured in the ith i=1 test.

T, is the adjusted analysis mean scrain t ime diere: Hg = total number of act ive rode measuicd in

, to the 201 insertion position. the first test following core alterations.

0.710 = the mean scrain t ime used in the 1 g analysis.

H 0.0875 = 1.65so.053 diere 1.65 is the appropriate g

To - 0.710 + 0.0873 statistical number to provide a 95%

n confidence level and, 0.053 is the i k N j stenJard devistion of the distribut inni

\ 1 / for average scrain insert ion t ime to the

, 4 201 posit lon, that was used in the i

j analysis.

3.3/4.3 BASES 90 REV a

1 #

4 i

)

3.0 LIMITING CONDITIONS FOR OPERATION 4.0 SURVEILIANCE REQUIREMENTS F. (Deleted) F. (Deleted) 4 i G. Jet Pumps G. Jet Pumps i Whenever the reactor is in tne Startup or Run modes, Whenever r.here is recirculation flow with the all jet pumps shall be operable with the requirement reactor in the Startup or Run mode, operating that each individual jet pump diffuser to lower jet pumps shall be demonstrated Operable plenum differential pressure (D/P) percent deviation daily and following any unexplained change from average loop D/P shall not differ by more than in core flow, jet pump loop flow, recirculation 20% deviation from its normal range of deviation. loop flow, or core plate differential pressure, With one or more jet pumpo exceeding the stated by recording jet pump loop flows, recirculation criteria, evaluate the reason for the deviation, pump flows, recirculation pump speeds, and and in the circumstance that one or more of the jet individual jet pump D/P, and verifying that: i pumps are determined to be inoperable, the reactor shall be placed in a cold shutdown condition 1. The recirculation pump flow / speed within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, ratio deviation from normal expected operating range does not exceed 5%.

l i 2. The jet pump loop flow / speed ratio deviation from normal expected operating ran8e does not exceed 5%.

1 If either of these conditions are not met, i

determine individual jet pump D/P percent

deviation from average loop D/P and compare t to the Limiting Conditions for Operation.

It may be necessary to increase pump speed to above 60% to conclude whether a jet 1 pump is inoperable.

3.6/4.6 128 REV 4

i

5 1

3.0 LIMITING CONDITIONS FOR OPERATION 4.0 SURVEILLANCE REQUIREMENTS l 4

, H. Snubbers H. Snubbero l 1. Except as permitted below, all enubbers The following surveillance requirements apply l

listed in rehle 3.6.1 shall be operable to all snubbers listed in Table 3.6.1.

j above Colic Shutdown. Snubbers may be ,

inoperable in Cold Shutdown and Refueling Visual inspection of snubbers shall be 1.

Shutdown whenever the supported system conducted in accordance with the following is not required to be Operable. schedules

2. With one or more enubbers made or found to No. of Snubbera Found Next Required

! be inoperable for any reason when Operability Inoperable per Inspection Period le required, within 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />s: Inspection Period j 0 18 monthe + 25% >

a. Replace or restore the inoperable snubbers 1 12monthe][251 to Operable status and perform an engineer- 2 6 months + 251 Ing evaluation or inspection of the 3,4 124 days + 25%

supported componente, or 5,6,7 62 days + 251 8 or more 31 days + 251

b. Determine through engineering evaluation that the as-found condition of the snubber The required inspection interval shall not be had no adverse effect on the supported lengthened more than one step at a time.

components and that they would retain their structural integrity in snubbers may be categorized in two groups, the event of the design basis seismic " accessible" or " inaccessible" based on their event, or accessibility for inspection during reactor l cperation. These two groups may be inspected t c. Declare the supported system inoperable independently according to the above schedule.

and take the action required by the d

Technical Specifications for inoper-ability of that system.

i 3.6/4.6 129 R F.V

! 3.0 LIMITING CONDITIONS FOR OPERATION 4.0 SURVEILLANCE REQUIREMENTS

3. Functional testing of snubbers shall be i conducted at least once per Operating Cycle during cold shutdown. Ten percent of the total number of each brand of snubber shall be functionally tested either in place or in -

l a bench test. For each snubber that does i not meet the functional test acceptance '

) criteria in Specification 4.6.H.4 below, i an additional ten percent of that brand shall be functionally tested

) until no more failures are found or '

i all snubbers of that brand have been l tested.

l The representative sample selected for functions 1 testing shall include the various configurations, operating environments, and  ;

the range of size and capacity of the snubbers.

- In addition to the regular sample and specified  !'

' re-samples, snubbers which failed the previous 4

functional test shall be retested during the

- next test period if they were reinstalled as a safety-related snubber. If a spare snubber l has been installed in place of a failed safety related snubber, it shall be tested during the next period.

If any snubber selected for functional testing either fails to lockup or fails to move l (i.e. frozen in place) the cause shall be i evaluated and if caused by manufacturer or i design deficiency, all snubbers of the same j design subject to the same defect shall be

]

functionally tested.

3.6/4.6 130s l REV i

l I

1

TACLE 8.6.1 SAFETY RELATED HYDRAULIC CNUSCERS

~

ENUSEER NO. SYSTEM LOCATION ELEVATION AZIMUTH ACCESSISLE -A (AIRLOCK 0 REF) INACCESSISLE-I PSt-H2 MAIN STEAM DRYWELL 953 071 I PSt-H3 MAIN STEAM CRYWELL 950 148 I PS2-H2 MAIN STEAM DRVWELL 950 120 I PS3-H2 NAIN STEAM DRYWELL 950 040 I PS4-H3 MAIN STEAM DRYWELL 950 212 I RV24-H3 SAFETY-RELIEF ORYWELL 950 110 I RV 4-H4 SAFETY-RELIEF DRYWELL 935 100 I RV04-H4A SAFETY-RELIEF DRYWELL 935 100. I RV24-H5 SAFETY-RELIEF DRYWELL 935 lie I RV24-NS: SAFETY-RELIEF DRYWELL 934 001 I RV24-HS3 SAFETY-RELIEF DRYWELL 962 090 I RV24-N1 SAFETY-RELIEF DRYWELL 953 090 I RV24A-H4A SAFETY-RELIEF DRYWELL 947 044 I QV24A-H7 SAFETY-RELIEF DRYWELL 953 000 I RV24A-He SAFETV-RELIEF DRYWELL 939 03: I RV:4A-N51 SAFETY-RELIEF DRYWELL 952 050 I RV24A-NS2 SAFETY-RELIEF DRYWELL 952 055 I RV24A-N1 SAFETY-RELIEF 2RYWELL 956 006 I RVCS-HI SAFETY-RELIEF DRYWELL 953 100 1 RV05-H1A SAFETY-RELIEF DRYWELL 953 100 I Rv23-HO SA>7TY-RELIEF DRYWELL 940 190 I RVOS-HOA SAFETY-RELIEF DRYWELL 944 190 I RV25-H3 SAFETY-RELIEF DRYWELL 934 100 I RVOS-HS1 SAFETY-RELIEF DRYMELL 952 140 I RV 5-NS2 SAFETY-RELIEF DRYWELL 952 195 I RVOS-NS3 SAFETY-RELIEF DRYWELL 921 150 I RV25A-HO SAFETY-RELIEF DRYWELL 945. 100 3 RV:5A-H3A SAFETY-RELIEF DRYWELL 945 300 I RVOSA-HF SAFETY-RELIEF DRYWELL 953 135 I RVOSA-NSI SAFETY-RELIEF DRYWELL 934 110 I RVOSA-NSO SAFETY-RELIEF DRYWELL 934 100 I RV 5A-NS3 SAFETY-RELIEF DRYWELL 952 102 I RVO6-H1 SAFETY-RELIEF DRYWELL 953 000 I RV06-HIA SAFETY-REtIEF DRYWELL 953 O'00 I RV 4-H2 SAFETY-RELIEF DRYMELL 947 000 1 RV26-HOA SAFETY-RELIEF DRYWELL 947 000 I RVO4-N1 SAFETY-RELIEF DRYWELL 956 000 1 RVO6A-H2 SAFETY-RELIEF DRYWELL 940 250 I RVO6A-HOA SAFETY-RELIEF DRYWELL 935 250 I RVO4A-NSI SAFETY-RELIEF DRYMELL 934 040 I RVO4A-NS2 SAFETY-RELIEF DRYWELL 934 030 1 RVO6A-NS3 SAFETY-RELIEF DRYWELL 900 057 I RV:6A-N1 SAFETY-RELIEF DRYWELL 950 250 I RV24A-N SAFETY-RELIEF DRYWELL 951 050 I RV 7-H1 5AFETY-RELIEF DRYWELL 950 300 I Rv27-H1A SAFETY-RELIEF DRYWELL 950 230 1 RVO7-HS SAFETY-RELIEF DRYWELL 945 270 3 3.6/4.6 ~ .131 REV

1 TAELE 3.6.1 l RAFETY RELATED HYORAULIC ENURRERO I ,

'j ENUBEER NO. SYSTEN LOCATION ELEVATION

• AZINUTH ACCESSIBLE ~A i (AIRLOCK 0 REFI INACCESSIBLE-I ,

Hv:7-H6 SAFETY-RELIEF DRYWELL 945 070 I RV27-NSI SAFEfY-RELIEF DRYWELL 934 250 I l i '

RV27-NSO SAFETY-RELIEF DRYWELL 934 280 I l RV27-N1 SAFETY-RELIEF ORYWELL S56 070 I f RV27A=HOA SAFETY-RELIEF DRYWELL 953 090 1 . 6 RV27A-H3 SAFETY-RELIEF DRYWELL 953 290 I RV27A-H9 SAFETY-RELIEF DRYWELL 938 090 I RV 7A-NSI SAFETY-RELIEF DRVWELL 950 082 I '

RV27A-NS: SAFETY-RELIEF ORYWELL 9b2 079 I AVO7A-NS3 SAFETY-RELIEF DRYWELL 952 080 I RV27A-N1 SAFETY-RELIEF DRYWELL 954 070 I ,

R6-N31 SAFETY-RELIEF DRYWELL 952 000 I l 4

SS-1 NAIN STfAN DRYWELL 953 279 I 55-1AR RECIRCULATION DRYWELL 922 315 I .

SS-1GR RECIRCULATION DRYWELL 922 135 I SS-11 FEEDWATER DRYWELL 950 302 I 52-12 FEEDWATER DRYWELL 952 OSS I S3-13 FEEDWATER DRYWELL 952 258 1 50-14 FEEDWATER DRYWELL 952 096 I 55-17A RHR ORYWELL 964 072 I SS-173 RHR DRYWELL 964 072 I SS-18A RHR ORYWELL 964 288 1 j SS-1CS RHR DRYWELL 964 288 I SS-19 MHR DRYWELL 964 341 I j SS-2 NAlte STEAN ORYWELL 953 081 1

! SS-CAR RECIRCULATIOt4 DRYWELL 927 302 I SS- BR RECIRCULATION DRYWELL 907 120 1 SS-00 RHR ORYWELL 964 019 I 35-3 NAIN STEAN ORYWELL 950 012 I

• SS-3AR R E C I R CUL A T I Ot4 DRYWELL 927 308 I SS-3RR RECIRCULATION DRYWELL 927 148 I ES.4 NAIN STEfM DRYWELL 950 148 I SS-4 ARIA) RECIRCULATICN DRYWELL 934 302 i SS-4ARtBI REC 13CULATION ORYWELL 934 33 I SS-4CRIAI RECIRCULATICH DRYWELL ^Je 120 1 S8-402881 RECIRCULATION DRYWELL 934 149 1 55 49 HPCI MAIN STEAN CHASE I

' ES-5AR RECIRCU?.ATION DRYWELL 941 315 I i SS-EBR R E CI R CUL AT I OP4 DRYWELL 941 135 1 SS-6AR RECIRCULATIDt1 DRYWELL 953 261 1 SG-40R RECIRCULATION DRYWELL 953 099 I SR-7 NAIN STEAN CRYWELL 953 240 I SS-7AR RECIRCULATION ORYWELL 953 323 I S3-78R RECIRCULATION ORYWELL 953 030 1 i SS-4 NAIN STEAN DRYWELL 953 120 I

] $0-SAQ RECIRCULATION ORYWELL 907 070 I

' SS-61R RECIRCULATION DRYWELL 927 090 I 3.6/4.6 132 REV

TAILE 3.6.1 SAFETY RELATEC HYORAULIC SNUICERS SHUE3ER NO. SYSTEM LOCATION ELEVATION AZIMUTH ACCESSISLE -A (AIRLOCK 0 REF) INACCESSIBLE-!

05-21 MHR TORUS FL LV - S WALL A 55-22 RHR TORUS FL LV - S WALL A SS-23 RHR S RHR ROON FL LV A C5-24 RHR A RHR ROCH FL LV A 55-05 RHR TORUS CATWK-SE WALL A

, SS-06 CORE SPRAY B RHR ROON FL LVL A ES-27 CORE SPRAY B RHR ROOM FL LVL A i SS-OSA CORE SPRAY A RHR ROON FL LVL A SS-28B CORE SPRAY A RHR ROOM FL LVL A

> 55-20 RHR OVER NO ANALYZER 954 A 23-30 RHR OVER N2 ANALYZER 954 A SS-31 MHR TORUS CATHK A SS-30A RHR A RHR ROON a BY HX 916 A ES-303 RHR A RHR ROOM - BY HX 916 A CS-33 RHR ABOVE TORUS A ES-34 RHR ABOVE TORUS A 55-35 HPCI HPCI ROOM - N HALL 912 A =

EU-3SA HPCI HPCI ROOM -FL LVL A 55-36B HPCI HPCI ROON - FL LVL A 55-37 HPCI HPCI ROOM - W WALL 905 A SS-38A RCIC RCIC ROOM - W WALL 906 A SS-383 RCIC RCIC ROOn - W WALL 906 A ES-41 CORE SPRAY ABOVE TORUS CATWK 907 A SS-42 HPCI ABOVE TORUS RING HOR 906 A 3.6/4.6 -

132a REV

I -

Bases Continued 3.6 and 4.6:

G. Jet Pumps By monitoring jet pump performance on a prescribed schedule, significant degradation in performance that would precede jet pump failure can be detected. An inoperable jet pump is not, in itself, a sufficient reason to declare a recirculation loop inoperable, but it may present a hazard in the event of a

large break accident by reducing the capability of reflooding the core; thus, the requirement for shutdown of the reactor with an inoperable jet pump.

The jet pump performance monitoring procedures are comprised of the following tests:

1 1. Core Flow versus Square Root of Core Plate Differential Pressure:

1 change in core resistance is the main contributor to recirculation system performance changes. If core resistance increases, it requires more energy (pump speed) to produce rated core flow.

j If resistance decreases, less speed is needed.

j 2. Recirculation Pump Flow / Speed Ratio: the pump operating j characteristic is determined by the flow resistance from the

loop suction through the jet pump nozzle. Since this resistance t

] is essentially independer.t of core power, the flow is linearly i proportional to pump speed, making their ratio a constant . .

j (flow / RPM is constant). A decrease in the ratio indicates i a plug, flow restriction, or loss in pump hydraulic performance.

l An increase indicates a leak or new flow path between the i recirculation pump discharge and jet pump nozzle. *l

3. Jet Pump Loop Flow / Recirculation Pump Speed Ratio: this relationship is an indication of overall system performance.

I 4. Jet Pump Differential Pressure Relationships: if a potential problem is indicated, the individual jet pump differential pressures are used 4

to determine if a problem exists since this is the most sensitive in-1 dicator of significant jet pump performance degradation.

)

i l

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}

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j 3.6/4.6 153 REV

1 .

3.0 LIMITING CONDITIONS FOR OPERATION 4.0 SURVEILLANCE REQUIRENENTS -

l 4. Pressure Suppression Chamber-Drywell Vacuum 4. Pressure Suppression Chamber-Drywell i

Breakers Vacuum Breakers i

a. When primary containment is required, all a. Operability and full closure of the

]

drywell-suppression chsaber vacuum breakers drywell-suppression chamber vacuum shall be operable and positioned in the breakers shall be verified by performance closed position as indicated by the of the following:

position indication system, except during testing and except as specified in (1) Honthly each operable drywell-3.7.A.4.b through 3.7.A.4.d below. suppression chamber vacuum breaker shall be exercised through

b. Any drywell-suppression chamber vacuum an opening-closing cycle.

breaker may be nonfully closed as l indicated by the position indice. tion and (2) Once each operating fuel' cycle.,

alarm systems provided that drywell to drywell to suppression chsaber leakage l suppression chamber differential pressure shall be demonstrated to be less decay does not exceed that shown on Figure than that equivalent to a one-inch

, 3.7.1. diameter orifice and each vacuum breaker shall be visually inspected.

c. Up to two drywell-suppression chamba- (Containment access required)

vacuum breakers may be inoperable provided that

(1) the vacuum breaker., (3) Once each operating cycle, vacuum i are determined to be fully closed and at breaker position indication and least one position alarm circuit is alarm systema shall be calibroted and operable or (2) the vacuum breaker is functionally tested. (Containment

secured in the closed position, access required) f d. Drywell-suppression chsmber vacuum (4) Once each operating cycle, the breakers may be cycled, one at a

• vacuum breakers shall be tested to time using the exercise test push- determine that the force required to button, during containment inerting open each valve from fully closed to and deinerting operations to assist fully open does not exceed that in purging air or nitrogen from the equivalent to 0.5 psi acting on the suppression chamber vent header. suppression chamber face of the -

i valve disc. (Containment access required) 164 REV 3.7/4.7

~ .

3.0 LIMITING CONDITIONS FOR OPERATION 4.0 SURVEILLANCE REQUIREMENTS

d. One position alarm circuit can be inoperable b. When the position o,f any drywell-providing that the redundant position alarm suppresalon chamber vacuum breaker valve circuit is operable. Both position alarm is indicated to be not fully closed at a circuits may be inoperable for a period not time when such closure is required, the to exceed ses-n days provided that all vacuum drywell to suppression chamber differential breakers are operable. pressure decay shall be demonstrated to be less than that shown on Figure 3.7.1 Lamediately and following any evidence of subsequent operation of the inoperable valve until the , inoperable valve is restored to a normal condition.

c. When both position alarm circuits are made or found to be inoperable, the control panel indicator light status shall be recorded . daily to detect changes in the vacuum breaker position.

5. Containment Atmosphere Control 5. Containment Atmosphere control

a. The primary containment atmosphere shall a.Whenever inerting is required, the primary be reduced to less than 57, oxygen with containment oxygen concentration shall be nitrogen gas whenever the reactor is in measured and recorded on a weekly basis, the run mode, except as specified in 3.7.A.5.b.

b. Within the 24-hour period subsequent to placing the reactor in the run mode following shutdown, the containment atmosphere oxygen concentration shall be -

reduced to less than 51 by weight, and maintained in this condition. Deinerting may commence 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to leaving the run mode for a reactor shutdown. 165 REV 52 1/9/81 3.7/4.7

. 3. 0 LIMITING CONDITIONS.FOR OPERATION .

4.0 SURVEILLANCE REQUIREMENTS ,

c. Except for inerting and deinerting operations  !

permitted in (b) above, all containment purging and venting above cold shutdown shall be via

i. a 2-inch purge and vent valve bypass line. -

and the Standby Gas Treatment System. Inerting and deinerting operations may be via the 18-inch purge and vent valves (equipped wLth 40-degree limit stops) aligned to the Reactor -

Building plenum and vent.

6. If the specifications of 3.7.A cannot be met, the reactor shall be placed in a ,

cold shutdown condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. 8. Standby Gas Treatment System B. Standby Gas Treatment system ht least once per month, initiate from

! 1. Two separate and independer.t stardby m(90%) flow gas treatment system circuits shall be throug both circuits,of the standby operable at all times when secon(ary gas reatment system. In addition: -

i

- containment integrity is required, except as specified in sections a. Within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> from the time that one '

3.7.B.I.(a)and(b). standby gas treatment system circuit

!i r

is made or found to be inocerable for

a. Af ter one of the standby gas hyreasonanddailythereafterfor

! treatment system circuits is made next succeeding seven days, or found to be inoperable for any inttlate from the control room 3500 reason, reactor operation and fuel *

'7,(fl05)flowthroughtheoperable handling is permissible only during *gr

' the succeeding seven days, provided ,p$tofthestandbygastreatment that all active components in the .

other standby gas treatment system .

shall be demonstrated to be oper-

• i able within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and daily .

thereafter. Within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> follow-ing the 7 days, the reactor shall be

• placed in a condition for which the stahdby gas treatment system is not required in accordance with-Specification 3.7.C.I.(a) through (d).

- 166 3.7/4.7 agy

3.0 LIMr.DG CONDITIONS FOR OPERATION 4.0 SURVEILLANCE REQUIRDENPS i

c. At least once per quarter- Continued (2) With the reactor power less than 1

75% of rated, trip main steam isolation valves (one at a time) and verify closure time.

d. At least once per week the main steam-line power-operated isolation valves shall be exercised by partial closure j and subsequent reopening, i 2. in the event any isolation valve specified 2. Whenever an isolation valve liste<1 in in Table 3.7.1 becoues inoperable, reactor operation in the run mode may continue Table 3.7.1 is inoperable, the position of

! provided at least one valve in each line at least one fully closed valve in each line

! having an inoperable valve is closed. having an inoperable valve shall be recorded daily.

3. If Specification 3. 7.D.1 and 3.7.D.2 cannot 3. The isolation valves listed in Table 3.7.1

{ be met, initiate normal orderly shutdown shall be' demonstrated Operable prior to j

and have reactor in the cold shutdown returning the valve to service after maintenance, I

condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

repair, or replacement work is performed on i the valve or its associated actuator,' control,

) or power gircuit by performance of a cycling

! test and verification of operating time.

4.

4

' The valve seals of the drywell and suppression 18-inch purge and vent valves shall be replaced

at least once every five years.

3.7/4.7 '171 REV

TABE FRIMARY CCNEAIM4E2ff ISOLATION Isolation Valve Number of Group Identification Valves Maxia.um

, Operating Normal Inboard Outboard Time (Sec) Positicn 1 Main Steam Line Isolation 4 le 3 I TI 5 Open 1 Main Steam Line Drain 1 1 60 Closed I

1 Recirculation Loop Sample Line 1 1 60 Open 2 Drywell Floor Drain 2 60 Open 2 Drywell Equipment Drain 2 60 Open

'l 2 Drywell Vent -

2 60 Closed 2 Drywell Vent Bypass 1 60 Closed j 2 Drywell Purge Inlet 2 60

• Open 2 Drywell and Suppressien Chamber 1 ,

60 Closed i Air Makeup 2 Suppression Chamber to Drywell 1 60

• 0 pen N2 Recirculation 2 Suppression Chamber Vent 2 60 Closed l 2 Suppression Chamber Vent Bypass 1 60

• 0pe n 2 -

Shutdown Cooling System 1 1 120 Closed .

i

)

• Ope.: to maintain drywell-torus differential pressure. This differential pressure will be l removed and the valves will be normally closed following completion of the Mark I contairunent long term program modifications.

172 3.7/4.7

• REV

i -

Bases Continued:

One-inch opening of any one valve or a 1/8-inch opeing for all eight valves, measured at the bottom of the disc with the top of the disc at the sest. The position indication systen as designeJ to detect t closure within 1/8 inch at the bottom of the disc.

At each refueling outage and following any sigificant maintenance on the vacuum breaker valves, positive seating of the vacuum breakers will be verified by leak test. The leak test designed to demonstrate that leakage is less than that equivalent to leakage through a one-inchis conservatively

• orifice which is about 3% of the maximum allowable. This test is planned to establish a baseline for valve performance at as nearly as possibletheto start their of each operating. cycle and to ensure that vacuum breakers are maintained design condition.

condition for operation. This test is not planned to serve as a limiting During reactor operation, an exercise test of the vacuum breakers will be conducted monthly: This test will verify that disc travel is unobstructed and will provide verification that the valves are l

closing fully through the position indication system. If one or more of the vacuum breakers do not seat fully as determined from the leakage is within the maximum allowable.indicating system, a leak test will be conducted to verify that Since the extreme lower limit of switch detection capability is approximately 1/16" the planned test is designed to strike a balance between the detection switch capability to verify closure and the maximum allowable leak rate. A special test was performed to establish the basis for this limiting condition.

breakers were shissed 1/16" open at the' bottom of the disc.During Thethebypass first refueling outage all with area associated ten vacuum the shimming corresponded to 63% of the maximum allowable.I The results of this

3. 7.1. Two of the original ten vacuum breakers have since been removed. test are shown in Figure l

{

When a drywell-suppression chamber vacuum breaker valve is exercised through an opening-closing cycle

• the position indicating lights at the remote test panels are designed to function as follows: .

. Full Closed 2 Creen - On 2 Red - Off' Intermediate Position 2 Creen - Off 2 Red - Off

^

Full Open 2 Green - Off 2 Red - On The remote test panel ennstars of a push button to actuate the air cylinder for testing, two red lights, 179 3.7 EASES . litV

I Bases Continued:

and two green lights for each of the eight valves. There are four independent limit switches on each valve. ~ The two switches contrutting the green lights are adjuss.e1 to provide an indication of dis-opening of less than 1/R" at the bottom of the disc. These switches are also used to activate the valve position alarm circuits. The two switches controlling the red !!shts are adjusted to prnvide indication of the disc very near the full open position.

The control room alarm circuits are redundant and fait safe. This assures that no simple Isilure will 1 defeat als; ming to the control room when a valve is open beyond allowable and when power to the switches i

fails. The alare is needed to alert the operator that action must be taken to correct a malfuncticn '

or to investigate possible changes in valve position status, or both. If the alarm cannot be cleared due

{ to the inability to estabitsh indication of closure of one or more valves, additional testing is required.

The alarm system allows the operator to make this evaluation on a timely basis. The frequency of the j testing of the alares is the same as that required for the position indication system.

1 Operability of a vacuum breaker valve and the four associated indicating light circuits shall be established by cycling the valve. The sequence of the indicating lights will be observed to be that previously described. If both green light circuits are inoperable, the valve shall be conside' red I inoperable and a pressure test is required immediately and upon indication of subsequent operation.

If both red light circuits are inoperable, the valve shall be conside' red inoperable, however, no pressure test is required if positive closure indication is present.

The 5% oxygen concentration einimizes the possibility of hydrogen combustion following a loss of

. coolant accident. Significant quantities of hydrogen could be generated if the core cooling systems failed to sufficiently cool the core. The occurrence of primary system leakage following a major

! refueltog outoge or other scheduled shutdown is more probable than the occurrence of the loss of j coolant accident upon which the specified oxygen concentration limit is based. Permitting access to the

drywell for leak inspections during a startup is judged prudent in terna of the added plant safety i of f ered without significantly reducing the margin of saf ety. Thus, to preclude the possibility

{ of starting the reactor and operating for extended periods of time with significar.t leeks in the primary 4

system, leak inspections are scheduled during startup periods, when the prLmary system is at or near l rated operating temperature and pressure. The 24-hour period to provide inerting is judged to be sufficient .

I to perform the leak inspection and establish the required oxygen concentration. The primary containment is normally slightly pressurized during periods of reactor operation. Hitrogen used for inerting could leak out of the. containment but air could not teak in to increase oxygen concentration. Once the con-tainment is filled with nitrogen to the required concentration, no monitoring of oxygen concentration is necessary. Ilowever, at least once a week the oxygen concentration will be determined as added assurance.

i 3.7 BASES 180 i

REV e

I 1

3.0 1.lHITlHC CONDITIONS FOR OPERATION , 4.0 SURVEILI.ANCE NEQUIREHENTS

4. Station Battery System 4. Stat ion Bat tery Syst eve If one of the two 125 V battery systems or a. Every week tiie specific gravity one of the two 250 V battery systems

• is and voltage of the pilot cell made or found to be inoperable for any and temperature of the adjacent reason, an orderly shutdown of the reactor cells and overall battery volt age shall be initiated and the reactor shall be ineasured.

water temperature shall be reduced to less than 2120F within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> unless such battery systems are sooner made Operable

b. Every three smonths the measure-ments shall be made of voltage of each ceII to nearest 0.01 volt, specific gravity of each cell, and temperature of every -

fifth cell.

c. Every refueling outage, the station batteries shall be sub-jected to a rated load discharge '

test. lietermine specific gravity and voltage of each cell after the discharge.

5. 24V Battery Systems 5. 24V Bat tery Systeins .

From and af ter the date that one of the two a. Every week the specific gravity and 24V battery systems is made or found to be , voltage of the pilot cell and tempera-Inoperable for any reason, refer to Specifi- ture of adjacent cells ant. overall caton 3.2 for appropriate act ion. battery voltage shall be measured,

b. Every titree months the measurement s shall be made of voltage of cacti cell to nearest 0.01 volt, e g.ac i f ic gravity of each cell, and temperature

• Applicable only to single station 250 V battery until completion of plant modification adding second

• 3.9/4.9 250 V battery (1983). 203 REV O

i

. i.l j .

4 Bases 3.93 The general objective is to assure an adequate supply of power with at least one active and one standby source of power avs11uble for operation of equipment required for a safe plant shutdown, to suintain the plant in a safe shutdown condition, and to operate the required engineered safeguards equipment following an accident.

] AC for shutdown requirements and openstion of engineered asfeguards equitseent can be provided by either 1

of two active auf either of two standby (two diesel generators) sources of power. As shown in Section 8 of the FSAR, power can be, supplied to these plant auxiliary systems through either of two recarve tsuna-

! formers.

4 To provide for maintenance and repair of equipment and still have redundancy of power sources, the requirement of one active and one standby source of power was established. 'Ihe plant's asin generutor is not given credit as a source since it is not available during shutdown.

The plant 250 V de power is supplied by two batteries. Most station 250 V loads are supplied by the original station 250 V battery. A new 250 V battery has been installed for HPCI loads and may be used for other station loads in the future. Each battery is maintained fully charged by two associated chargers which also supply the normal de requirements with the batteries as a standby source during emergency conditions. The plant 125 V de power is normally supplied by two batteries, each with an associated charger. Backup chargers are available.

The mininsam diesel fuel supply of 26,250 gallons will supply one diesel generator for a minimum of j seven days of full load operation. Additional diesel fuel can normally be obtained within a few hours. Maintaining at least seven days supply is therefore conservative.

3 In the nomini mode of operution, power is avaliable from the off-aite sources. One diesel may be allowed l out of service based on the availability of off-elte power and the daily testing of the remaining diesel gene ra tor. Thus, though one diesel generator is tempurarily out of service, the eff-elte sources are available, as well us the remaining diesel generator. Based on a monthly testing period (Specification i  %.9), the seven day repuir period is justified. (1)

]

! (1) "Heliability of Engineered Sufety Features as a Function of Testing Frequency" I. M. Jacobs, i Huelear Safety, Voltmee 9, No. %, July - August 1968 1

1

~

204

~

3. ') HAS123 kgy 9

TABLE 3.13.1 SAFETY RELATED FIRE DETECTION INSTRUMENTS Minimum Instrumenta Operable Fire Zone Location Heat Flame Smoke I lA "B" RHR Room 3 IB "A" RHR Room 3 IC RCIC Room 3 l

. lE HPCI Room 2 IF Reactor Building-Torus Compartment 11 2A Reactor Bida. 935' elev - TIP Drive Area 1 28 Reactor Blds. 935' elev - CRD HCU Area gaat 10 2C Reactor 81ds. 935' elev - CRD HCU Area West 11 2E Reactor Bldg. 935' - LPCI Injection Valve Area 1 l

35 Reactor Blds. 962' elev - SBLC Area 2 3C Reactor Bldg. 962' elev - south 5

, 3D Reactor B1dg. 962' elev - RBCCW Pump Area 4

{ 4A Reactor Bldg. 985' elev - South 4 48 Reactor Bldg. 985' eley - RBCCW Hz Area 5 4D SBCT System Room 2 5A Reactor Bldg. 1001' elev - South 7 5B Reactor Bldg. 1001' elev - North 3 SC Reactor Bldg. - Fuel Fool Cooling Fump Ares 1 -

6 Reactor Building 1027' elev 5 7A Battery Room 1 75 Battery Room , 1 7C Battery Room -

1 8 Cable Spreading Room 7

12A Turbine Bldg. - 911' - 4.16 KV Switchgear 3 4

13C Turbine Bldg. - 911' elev - HCC 133 Area -

1 j 14 A- Turbine Bldg. - 931' - 4.16 KV Switchgear 2 15A #12 DG Roon & Day Tank Room 3 155 #11 DG Room & Day Tank Room 3 l_ 16 Turbine Bldg. 931' elev - Cable corridor 3 17 Turbine Bldg. 941' elev - Cable corridor 3 19A Turbine Bldg. 931' elev - Water Treatment Area 5 i 195 Turbine Bldg. 931' elev - HCC 142-143 Area 1 19C Turbine Bldg. 931' elev - FW Pipe Chase 1 20 Heating Boiler Room 1 23A Intake Structure Pump Room 3 3.13/4.13 - 227c 1 ~

REV

5.0 DESIGN FEATURES 5.1 Site A. The reactor center line is located at approximately 850,810 feet North and 2,038,920 feet East as determined on the Minnesota State Crid, South Zone. The nearest site boundary is approximately 1630 feet S 30 W of the reactor center line and the exclusion area is defined by the minimum fenced area shown in FSAR Figure 2.2.2a. Due to the prevailing wind pattern,' the direction of maximum integrated dosage is SSE. The southern property line follows the northern boundary of the right-of-way for the Burlington Northern Railway.

5.2 Reactor A. The reactor core shall consist of not more than 484 f uel assemblies.

i B. The reactor core shall contain 121 cruciform-shaped control rods. The control rod material shall be boron carbide powder (B,C) compacted to approximately 70% of theoretical density.

n i 5.3 Reactor Veusel A. The pressure vessel shall be designed far a pressure of 1250 peig and a temperature of 575 F.

The coolant recirculation system shall be designed for a pressure of 1148 psig on auction side of

! pump and 1248 psig at pump discharge. The applicable design codes shall be as described in l Sections 4.2.3 and 4.3.1 of the Monticello Final Safety Analysis Report.

5.4 Containment A. The primary containment shall be of the pressure suppression type having a drywell and an gbsorption

, chamber constructed of steel. The drywell shall have a volume of approximately 134,200 ft and

, is designed to conform to ASME Boiler and Pressure Vessel Code Section 111 Class B for an internal I

pressure of 56 psig at 281 F and an external pressure of 2 pagg at 281 F. The absorption chamber shall have a total volume of approximately 176,250 ft 5.0 230

. REV ,

1 N

i -

+

e l

-l E. A training program for individuals serving in the fire brigade shall be maintained under the i

direction of a designated member of Northern States Power saanagement. This program shall meet l the requirements of Section 27 of the NFPA Code - 1976 with the exception of training scheduling.

Fire brigade training shall be scheduled as set forth in the plant training program.

I 5

i l

l i

6.1 233

, REV

PRESIDENT .

I SENIOR VICE PRES 10ENT POWER SUPPLY i

I I I VICE PRESIDENT DIRECTOR DIRECTOR MANAER DIRECTOR H

PLANT ENCItfERING OUALITY SYSTEM PR00 ftKL NUCLEAR l OP & Malt 4TENANCE SUPPLY ENERATION

• j AND ECHSTR!CTION ASSURANCE l

NERAL MANAER CEttRAL MANAGER t1EADouARTER$

i NUCLEAR PLANTS #0 CLEAR GROLP I I I MANAGER GENERAL SUPT GEtERAL SUPT MANAGER PLA#4(

PRODUCTION HUCLEsa TECHNICAL NUCLEAR SUPPORT MANAGERS ANALYSIS SERVICES SERvlCES

&fiAIRIE ISLArc TRAIPHNO

. & MONTICELLO) I sp f 1 ON-SITE TECHNICAL I OH-SITE l igAINING SERVICES CROLPS ADMINISTRATION 1 I l I 1 I I I I i I WTY AUDif

( AUDIT & REvlEW OF 7gggggg--- ---------------------." COMMITTEE (SAC) i

! O HAS THE liESPONSIBil!!I FOR THE FIRE FROTECTION PROGRAM FIGURE 6.1.1 NSP CORPORATI0t4 ORGAtil2ATION RELATI0t4 SHIP TO Oti-SITE DPERATit4G ORGAt4IZAllGN 6.1 234 REV

PLANT r CPERAT40NS MANAGER e N CopeilfTEE PLANT St.FERINTEPOENT SWT. StPT. PLANT PLANT SLPER]NTEPOENT OPERATIONS & SECLAITY & QUALITY OFFICE ENGIEERING &

MAINTENANCE e SERVICES e ENGINEERING e MANAGERe RADIATION PROTECT 30N S ES00 I

i

- l SUPE 0Ri FOR OA AND OC FUNCTION SUPT.0F SUPT.0F g g MAINTENANCE e OPERATIONS e WT. MT. MT.

J RADIATION TECmlCAL OPERATIONS

' PROTECTION

• ENGINEERING e ENGIEERING e SITE SwT.

Q.503 u

MCHANICAL StGFT StPER- TECHNICAL ENGIEERS TEC mlCAL

& VISOR ILSCI SUPPORT & FOR NUCLEAR StFPORT FOR ELECTRICAL RADIATION ENGINEERING, OPERATION, g

HAINTENANCE PROTECTION INSTRLMENTATION, HAINTENANCE.

OROUP LEAD PLANT EQUIP- SPECIALISTS CONTROLS. SURVE1LLANCE.

M NT & REACTOR COPfUTER & TESTING ,

OPERATOR LO) INSTRLMNTS &

CONTROLS SPEC PLANT EQUIPMNT

& REACTOR OPERATOR (SP EO)

ASSISTANT PLANT C00Ee

• KEY SLPERVISOR EQUIPMNT LO LICErtSED OPERATOR OPERA 10fHS3 L50 LIL(NSED SENIOR OPERATOR ND PLANT ATTEPOANTS

~

FIRE BRICADE LAS REQUIRED)

FIGURE S.I.2 MONTICELLO NUCLEAR GENERAT]NG PLANT FUNCT10NAL ORGANIZATION FOR ON-SITE OPERAT]NG GROUP 235 6.1 REV

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b. When the nature of a particular problem dictates, special consultants will be utt11 sed, as necessary, to provide empart advice to the SAC.

i .

' 3. Heating Frequency I The SAC shall meet on call by the Chairmasi but not less frequently than twice a year.

l 4. Quorum .

a. Ho less then a majority of the permanent members- or their alternates, inclue.46 the .

1 SAC Chairman or Vico Cheltman..

b. No more then a minortty cf -l o quornie risalt be fros grosips holding line respocolbility i

for the operation of clse plar.t.

5. Responsibilities - The following subjecta should he reported to or . reviewed by the SAC:

4 1

l a. Written safet3 evaluentiins c.f (1) changes in the f acility, (2) changes to procedures, and (31 tests or emperiments cumpleted without prior Commission approval under the provisions of 10 CFR 50.59 to verify that such changes, tests or experiments did not involve a change in the Appendix A TechnicmL Spectiieations or an unreviewed .

1 safety question as defined in 10 CFA 50.59.

,l b. Proposed changes to procedures, change s in the f acility, and tests and esperiments which may involve a change in the Appendix A teclinical specifications or an unreviewed i

safety quescion as defined in 10 CFR 50.59. Hatters of this kind shall be referred to the l

i SAC folloutng their rewtew by the onsite operating crgantastion.

i

c. Proposed changes in Appendix A Technical specifications or proposed license amendments

• l relating to nuclear safery.

d. Violations of applicable codes, regulations, orders. Appendix A Technical Specifications, and license requirementa or internal procedures or instructions having nuclear safety significance.

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1 I a. Significant operating abnormalities or deviations from normal and espected performance

• of plant safety-related structures, systema, or components.

j 2

• 238 i

- REV 6.2 ,

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i f.

Investigation of all evento 4 3ch are required by regulatinn or technical specifications to be reported to NRC in' writ ing within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. .

g.

~ Revisions to the Facility Emergency Plan, the Facility Security Plan, and the Fire Protection Program.

h. Operations Committae minutes to determine if matters considered by that Comisittee involve unreviewed or unresolved safety questions.

l.

Other nuclear safety matters referred to the SAC by the Operations Committee, plant management or company management, i

). All recognized indications of an unanticipated deficiency in come aspect of dealgn or operation of safety-related structures, systems, or components. '

k. Reports of special inspections and audita conducted in accordance with specification 6.3.

6. Audit - The operation of the nuclear pouer plant shall be audited formally under the cognizance of time SAC to assure safe facility operation.

l a. Audits of selected aspects of plant operation, as delineated in Paragraph 4.4 4

of ANSI Mla.7-1972, shall be performed with a frequency commensurate with their nuclear safety signifle.ance and in a manner to assure that an audit of all nuclear safety-related activities is completed within a period of two years.'

The audits shall be performed in accordance with appropriate written instructions j and procedures.

{ b. Periodic review of the audit progress should be performsd by the SAC at least twice a year to assure its adequacy.

c.

Written reports of the audits shall be reviewed by the Director Nuclear Generation, by the SAC at a scheduled meeting, and by members of Management '

having responsibility in the areas audited.

6.2 239 pgV

7. Authority .

1he SAC shall be advisory to the Director Nuclear Generation.

8. Records Minut'es shall be prepared and retained for all scheduled meetings of the Safety Audit l Committee.

The minutes shall be distributed within one month of the meeting to the l Director Nuclear Generation, the General Manager Nuclear Plants, each There member shall of the be a formal SAC, and others designated by the Chairman or Vice Chairman, i

' approval of the minutes.

9. Frocedures A written charter for the SAC shall be prepared that containst s'. Subjects within the purview of the group.

b. Responsibility and authority of the group.

c. Hechanisms for convening meetings.

Frowlslons of use of specialists or subgroups.

d.

e. Authority to obtain access to the nuclear power plant operating record files and operating personnel idien assigned audit functions.

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f. Req' ult er ats for distribution of reports and minutes prepared by the group to others in the NSP Organisation.

9 240 6.2 ,

REV e

4

< . t 4

j B. Operatlons comai_ cee (OC) i .

2

1. Membership 1he Operations Committee sliall consist of at least six (6) members drawn f rom the key super-

, visors of the on-site supervisory staf f. The Plant Manager shall serve as Chairman of the ,

, DC and shall appoint a Vice Chairman from the DC membersip to act in his absence.

5

2. Heet ing Frequency i

I 1he operations cosamittee will meet on call by the Chairman or as requested by ' Individual members and at least monthly.

3. Quorum

A quorum shall include a majority of the permanent members, including the Chairman or Vice Chairman

4. Responsibilities - The following subjects shall be reviewed by the operations cosamittees

a. Proposed tests and experiments.and their results.

! b. Modifications to plant systems or equipment as described in the Updated Safety Analysis Report and having nuclear safety significance or which involve an unreviewed safety question as defined in 10 CFR 50.59.

j

c. Proposals deich would effect permanent , changes to normal and emergency operating j procedures and any other proposed changes or procedures that are determined by

] the Plant Hansger to af fect nuclear safety. ,

i i d. Proposed changes to the Technical Specifications or operating license.

i e. All reported or suspected violations of Technical Specifications, operating license requirement s, administrat ive procedures, or operating procedures. Results of investi-

! getions Including evaluatton and recommendetIons to prevent recurrence, will be

' reported, in writing, to the Ceneral Manager Nuclear Plants and to the Chairmaa j .of the Safety Audit Committee.,

6.2 241 KEV j

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I 6.5 Plant operatina Procedures Detailed written procedures, including the applicable check-off lists and instructions, covering areas listed below shall be prepared and followed. These procedures and changes thereto, except as specified below, shall be reviewed by the Operations Comittee and approved by a member of plant management designated by the Plant Manager.

A. Pinnt Operations

1. Integrated and system procedures for normal startup, nparation and shutdown of the -

reactor and all systems and components involving nuclear safety of the facility. .

2. Fuel handling operations.

3. Actions to be taken to correct specific and foreseen potentist or actual malfunctida of systems or components including responses to alarms, primary system leaks and abnormal reactivity changes gna teclading i follow-up actions required after plant

, protective system actions hava initiated.

i l 4. Surveillance and testing requirements that could have an effect on nuclear safety.

5. Implementing procedures of the security plan. .

6 Implementing procedures of the Facility Emergency Plan, including procedures for coping with l emergency conditions' involving potential or actual releases of radioactivity.

7. Implementing procedures of the fire protection program.

l l Drills on the procedures specified in A.3 above shall be conducted as a part of the retraining program. _

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,, 2t.4 -

6.5 I

i !

i B. Radiological 1.a. A Radiation Protection Progran , consistent with the requirements of 10 CFR 20, shall be developed and followed. The Radiation Protection Program shall consist of the following:

) (1) A Radiation Protection Plan, which shall be a complete and concise statement of radiation protection policy and program f (2) Procedures which implement the requirements of the Radiation Protection Plan l

The Radiation Protection Plan and implementing procedures, with the exception of those l

non-safety related procedures governing work activities exclusively applicable to or performed by health physics perscnnel, shall be reviewed by the Operations Canmittee i and approved by a member of plant management designated by the Plant hhnager.

b. Paragraph 20.203 " Caution signs, lables, signals and controls." In lieu of the " Control device"

.! or alarm signal required by paragraph 20.203(c)(2), each high radiation area in which the intensity of radiation is 1000 mrem /hr or less shall be barricaded and conspicuously posted as a high radiation area and entrance thereto shall be controlled by requiring issuance of a

- Radiation Work Permit and any individual or group of individuale permitted to enter such areas shall be provided with a radiation monitoring device which continuously indicates the radiation dose rate in the area.

)

c. The above procedure shall also apply to each high radiation area in which the intensity of radiation is greater than 1000 mrem /hr, except that doors shall be locked or attended to prevent unauthorized entry into these~ areas and the keys or key devices for locked doors shall be maintained under the administrative control of the Plant Manager.

l 6.5 244a REV i

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2. A program shall be implemented to reduce leakage from systems outside containment that would or could contain highly radioactive fluids during a serious transient or accident to es low as practical levels. This program shall include the followings

a. Provisions establishing preventive maintenance and periodic visual inspection require-ments, and ,

l i b. Integrated leak test requirements for each system at a frequency not to exceed refueling cycle intervals.

A program acceptable to the Commission was described in a letter dated December 31, 1979, I

from L 0 Mayer, NSP, to Director of Nuclear Reactor Regulation, " Lessons Learned 1 Impleme nt at ion". .

I

3. A program shall be implemented which will ensure the capability to accurately determine i the airborne iodine concentration in essential plant areas under accident conditions. This program chall include the following:

a. Traliing of personnel. -

b, Procedures for monitoting, and l c. Prcvisions for maintenance of sampling and analysis equipment.

A progtam acceptable to the Commission was described in a letter dated December 31, 1979,

from L 0 Mayer, NSP, to Director of Huclear Reactor Regulation, " Lessons Learned Implementation".

, 245 6.5 .

REV

i 4 EXHIBIT C License Amendment Request Dated September 24. 1982 .

MONTICELLO NUCLEAR GENERATING . PLANT MAIN STEAMLINE TUNNEL TEMPERATURE SWITCHES TECHNICAL SPECIFICATION MODIFICATION Prepared for:

NORTHERN STATES POWER COMPANY Minneapolis, Minnesota i Prepared by:

EDS Nuclear Inc.

Walnut Creek, California November 1981 EDS Report No. 01-0910-1151, Rev. 2 l

Paga i EDS NUCLEAR INC.

REPORT APPROVAL COVER SHEET ,

Client. NORTHERN STATE.9 POWFR FO-Project: MONTICELLO ENVIRONMENTAL ANATNSTn Job Number: 0910-001-471 MONTICELLO NUCLEAR GENERATING PLANT MAIN STEAM TUNNEL Report

Title:

TEMPERATURE SWITCHES TECHNICAL SPECIFICATION MODIFICATION Report Number: 01-0910-1151 Rev. O De work described in this Report was performed in accordance with the EDS Nuclea:-

l Quality Assurance Program. De signatures below verify the accuracy of this Report and its compliance with applicable ality a surance requirements.

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Prepared By: M S N Date: .3-[9"II Benjamin R. Strong, Seniod Technical Specialist, SED Reviewed By: _%_w n __

NAh Date: b bNM Lawrence J. MeYcalfe, upeh ising Engineer, SED Approved By: Y7b [ '

/

f Date: .3 -/9 - 6/

Timothy K. Snycker,' Manager, Systems Engineering Division REVISION RECORD ll Rev. Approval No. Prepared Reviewed Approved Date Revision 1 1;f, l-WOl y n MI49=~ - ///>/f'/ M**(M 1

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t NORTHERN STATES POWER COMPANY Main Steamline Tunnel MONTICELLO NUCLEAR GENERATION PLANT Temperature Switches 01-0910-1151 Rev. 2 Page 11 Page TABLE OF CONTENTS Report Approval' Cover Sheet i Table of Contents il 1.0 Introduction 1-1 2.0 Scope 2-1 3.0 Method of Analysis 3-1 3.1 Assembly and Review of Input Data 3-1 3.2 Computer Analysis 3-2 4.0 Results and Conclusions 4-1 5.0 References 5-1 Appendix A: EDSFLOW Computer Program Description

4 NORTHERN STATES POWER COMPANY Main Steamline Tunnel MONTICELLO NUCLEAR GENERATION PLANT Temperature Switches 01-0910-1151 Rev. 2 Page 1-1 J. 0 INTRODUCTION Northern States Power Company (NSP) requested EDS Nuclear to provide engineering analysis of the setpoint for the main steamline tunnel temperature switches (MSTS). These switches are installed at the Monticello Nuclear Generating Plant. Plant Technical Specification basis states that the temperature switches are capable of detecting a pipe break on the order of 5 to 10 gallons per minute (gpm) in the main steamline. Currently, the Technical Specification requires the temperature switch setpoint to be maintained at 2E 200oF with a +20F deviation.

The purpose of the EDS Nuclear engineering analysis is to determine the temperature in the area of the temperature switches that will result from a pipe break in the order of 5 to 10 gpm.

This report documents the EDS Nuclear scope of work, methods, results and conclusions.

Also included is a list of the references ,

and a description of the computer program used in the analysis. This report is a revision of the EDS Report No.

01-0910-1151, Rev. 1 issued in September, 1981. The revision includes Northern States Power Company's comments on the Rev.

1 report.

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NORTHERN STATES POWER COMPANY Main Steamline Tunnel MONTICELLO NUCLEAR GENERATION PLANT Temperature Switches 01-0910-1151 Rev. 2 Page 2-1 1

2.0 SCOPE The scope of this report is an engineering evaluation of a main steamline pipe break in the main steamline tunnel at the Monticello Plant.

The size of the break considered is on the order of 5 to 10 gpm in either the main steamline or in the 3" main steam drain line.

The scope includes a computer analysis to determine the resulting temperature rise in the main steamline tunnel. Also included is an evaluation of the location of the temperature switches to detect the pipe break. The following temperature switches are considered:

TS 2-121A TS 2-122A TS 2-121B TS 2-122B TS 2-121C TS 2-122C TS 2-1210 TS 2-122D TS 2-123A TS 2-124A TS 2-123B TS 2-124B TS 2-123C TS 2-124C TS 2-123D TS 2-124D l The results of the analysis will provide the necessary data to determine what temperature switch setpoint will be adequate to maintain the existing level of safety function and break detection.

- - - - , , , - - .,, , , , , n .-, , _ , - - - - -

NORTHERN STATES POWER COMPANY Main Steamline Tunnel MONTICELLO NUCLEAR GENERATION PLANT Temperature Switches 01-0910-1151 Rev. 2 Page 3-1 3.0 METHODS OF A break on the order of 5 to 10 gpm in the ANALYSIS main steamline will discharge very low mass, high energy fluid into the main steamline tunnel. This would result principally in an increase in the sensible heat of the main steamline tunnel fluid.

Beat will be removed from the main steamline tunnel fluid through the main streamline tunnel walls, floor and ceiling and by the fluid carried through the HVAC system. The increase in the main steamline tunnel sensible heat will result in an increase in temperature, but not a significant change in pressure. The blcw out panel in main steamline tunnel would not be affected by this event.

The engineering analysis includes:

- a. Assembly and review of input data l

I

b. Computer analysis to determine the environmental conditions due to main steamline break.

The following sections describe each task in more detail.

3.1 ASSEMBLY AND The information relevant to the main REVIEW OF steamline tunnel area, including layout, INPUT DATA piping, and HVAC drawings were assembled and reviewed (References 1 through 10) .

The input data reviewed included:

a. Pipe ruptures identified in the main steamline tunnel.

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b. System conditions.

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c. Operations reports on MSTS function.

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NORTHERN STATES POWER COMPANY Main Steamline Tunnel MONTICELLO NUCLEAR GENERATION PLANT Temperature Switches 01-0910-1151 Rev. 2 Page 3-2

d. Elementary diagrams and isolation system logic diagram relating to MSTS function.

e. Applicable licensing materials.

The conditions and assumptions used for the evaluation of the main steamlines in the steamline tunnel are provided in Section 3.2.4.

A review of the applicable standards, regulations and licensing materials pertinent to the design and function of the MSTS (References 1 through 5) was performed to define the required limits of operation of MSTS. The existing Monticello Technical Specification describes the function of the teniperature switches. Trips are provided on this instrumentation and when exceeded cause closure of Group 1 isolation valves.

' For large breaks, this signal is a backup to high steam flow instrumentation. For small breaks with the resultant small release of radioactivity, it provides isolation before the guidelines of 10CFR100 are exceeded (Reference 7) .

3.2 COMPUTER Based on a postulated break in the main ANALYSIS steamline on the order of 5 to 10 gpm, a computer model of the main steamline tunnel was developed to calculate the resulting pressure and temperature time histories (Reference 11) .

The following are included in the model:

a. The HVAC System (Flow Path).

b. The heat transfered from the processed fluid into the main steamline tunnel.

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NORTHERN STATES POWER COMPANY Main Steamline Tunnel  !

MONTICELLO NUCLEAR GENERATION PLANT Temperature Switches 01-0910-1151 Rev. 2 Page 3-3

c. The concrete walls in the main steamline tunnel.

d. The blowdown from the break in the main steamline.

3.2.1 COMPUTER MODEL The computer program EDSFLOW was used to DESCRIPTION model the main steamline tunnel. EDSFLOW is the EDS Nuclear proprietary version of the RELAP4/ MODS thermal-hydraulics computer program. The principal capabilities of the EDSFLOW computer code are described in Appendix A.

In the present analysis the code uses the Containment Option (air present) and represent: the main steamline tunnel and HVAC system as a series of interconnected control volumes. Pipe break blowdown was input to the code and the flow between volumes was determined at each time step based on internal flow or homogeneous equilibrium critical flow.

The model used in this analysis is shown in Figure 3-1.

t 3.2.2 HEAT STRUCTURE It was necessary to model heat-conducting MODELING structures in the main steamline tunnel to correctly determine the long term temperatures.

The concrete walls are modeled as heat sinks to represent the heat absorption capability of the main steamline tunnel structure. The heat transferred from the processed fluid is modeled as an additional heat source in the main steamline tunnel.

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NORTHERN STATES POWER COMPANY Main Steamline Tunnel MONTICELLO NUCLEAR GENERATION PLANT Temperature Switches  ;

01-0910-1151 Rev. 2 f

Page 3-4 l

3.2.3 FLOW PATH Normal junctions between volumes such as MODELING the HVAC ducting were modeled as vent paths to distribute the blowdown mass throughout the system. The blowout panel between .the main steamline tunnel and the turbine building heater bay area was excluded from the model because the main steamline tunnel would not attain the pressure necessary to blow out the panel. This is confirmed by the results obtained in Reference 11. The minimum differential pressure required to blow out the panel is 0.25 paid (Reference

1) .

3.2.4 BLONDOWN FLUID The fluid properties in the main steamline PROPERTIES and main steamline to condenser piping were taken for a reactor pressure at 102% power.

This corresponds to a fluid pressure of 1040 psia and an enthalphy of approximately 1190 Btu /lbm.

l-. - - - . . - . . - - . _ _ - - _ . - . . - . . . - . - - - - - - . . - - - - - - . - - .

e NORTHERN STATES POWER COMPANY Main Steamline Tunnel MONTICELLO NUCLEAR GENERATION PLANT Temperature Switches 01-0910-1151 Rev. 2 Page 3-5 FIGURE 3-1 EDSFLOW COMPUTER MODEL EL 958.6' WAC FROM EL. 957.5' -

h MST TO STACK UPPER PORTION OF MAIN STEAMLINE TUNNEL (MST) T,4

@D l ATMOS.

{

> -EL. 943' uvAC s h PORTION OF MST

., _.__ CONTAINING TEMPER-j,,f ATURE SWITCHES AND 5 7

MAIN STEAMLINES Z X 7

., _. 1 STEAMLINE LEAK o -

h IDWER PORTION FROM OF MST 0 1 - votcMz 1 PROCESSED 2 FLUID X JUNCTION 2 EL. 931' l

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NORTHERN STATES POWER COMPANY Main Steamline Tunnel MONTICELLO NUCLEAR GENERATION PLANT Temperature Switches 01-0910-1151 Rev. 2 Page 4-1 4.0 RESULTS AND This section presents the results and CONCLUSIONS conclusions of the engineering analysis performed to determine the adequacy of the MSTS to detect the specified break.

RESULTS A break on the order of 5 to 10 gpm in the main steamline is sufficient to increase the main steamline tunnel temperature to 2120F.

During summer conditions, the 2120F temperature will be reached with a 5 gpm main steamline leak.

During the most limiting winter conditions the analysis results show the 2120F temperature threshold is reached due to a i 9 gpm break in the main steamline.

It should also be noted that the current location of the MSTS array is in adequate proximity to the piping to provide sensing of the high temperature without the necessity of the discharged fluid heating '

the entire main steamline tunnel to 2120F.

CONCLUSIOUS The analysis conducted yielded the following conclusions:

l

1. Any setpoint, when added to the temperature switch deviation, totaling 2120F or less is acceptable. This setpoint will be adequate to maintain the existing level of safety function and break detection.

2. The Technical Specification (Table l

3.2.6) may be revised by NSP to reflect this higher allowable temperature.

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NORTHERN STATES POWER COMPANY Main Steamline Tunnel MONTICELLO NUCLEAR GENERATION PLANT Temperature Switches 01-0910-1151 Rev. 2 Page 4-2

3. If the main steamline tunnel temperature switches are to be used to detect breaks other than in the main steamline, then i

analyses would have to be performed to assess the adequacy of the temperature switches for those functions. .

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NORTHERN STATES POWER COMPANY Main Steamline Tunnel MONTICELLO NUCLEAR GENERATION PLANT Temperature Switches 01-0910-1151 Rev. 2 Page 5-1

5.0 REFERENCES

1. "Monticello Nuclear Generating Plant Environmental Effects Due to Pipe Rupture ," EDS Report # 01-0910-1137, Rev. O, Dec. 1980

2. Letter of 2/15/80, Mr. C.B. Hogg (Bechtel) to Mr. M. Hammer (NSP) " Pipe Break Outside Containment Results,"

Bechtel Letter No. BLM:307/DCN:1953

3. " Postulated Pipe Failures Outside Containment," Monticello Nuclear Power Plant - Unit 1, with Supplements, Aug.

1973

4. United States Nuclear Regulatory Commission, NUREG-75/087 Standard Review Plan Section 3.6.1, " Plant j

Design For Protection Against Postulated Piping Failure in Fluid Systems Outside Containment,"

, 11/24/75, with Attachments APCSB 3-1 I

5. Monticello Nuclear Power Station Unit-1, Final Safety Analysis Report, Sections 2.7 and 6.3

6. EDS Calculations Nos. 1-7 for Job Nos, 0910-001-224 and 372 Monticello NP-1,

" Environmental Response Due to Pipe Rupture Outside Containment"

7. Monticello Nuclear Plant - Unit 1, Technical Specifications, Section 3.2 and Table 4.2.1, Rev . 5 2, 1/9/81.

NORTHERN STATES POWER COMPANY Main Steamline Tunnel MONTICELLO NUCLEAR GENERATION PLANT Temperature Switches 01-0910-1151 Rev. 2 Page 5-2

8. Bechtel drawings for Monticello Nuclear

- Generating Plant - Unit 1, Job No. 5628.

M-9 Rev 2, 11/4/70; Equipment Location Section A-A M-156 Rev 4, 8/21/70; Airflow Diagram Reactor Building Lower Part M-234 Rev 10,11/18/74 ; Area-3 Piping Drawings Plan Below El 948'-0" M-242 Rev 12, 3/12/75; Area-3 Piping Drawings Section C-C M-515 Rev 5,11/30/70; Reactor Bldg.

H&V Plan at El. 935'-0" M-516 Rev 5, 11/30/70 Reactor Bldg.

H&V Plan at El. 960 '-0"

9. GE-729E856 sht 3 of 4, Primary Containment Isolation System.

10. GE-225A4669, Rev. O Instrument Data Sheet on Item No. 2-121 A to D (MSTS), '

4/23/69.

11. EDS Calculation 0910-001-471-10.0, Rev.

0; Main Steam Tunnel Environment due to Leak in Main Steamline, September 1981.

NORTHERN STATES POWER COMPANY Main Steamline Tunnel MONTICELLO NUCLEAR GENERATION PLANT Temperature Switches 01-0910-1151 Rev. 2 Page A-1 APPENDIX A EDSFLOW COMPUTER PROGRAM DESCRIPTION

NORTHERN STATES POWER COMPANY Main Steamline Tunnel MONTICELLO NUCLEAR GENERATION PLANT Temperature Switches 01-0910-1151 Rev. 2 Page A-2 APPENDIX A The following section contains the EDSFLOW computer program abstract. This computer code was used by EDS to perform the compartment environmental thermal-hydraulic analysis for this project.

EDSFLOW COMPUTER EDSFLOW is a modified version of the PROGRAM DESCRIPTION RELAP4/ MOD 5 computer code developed at the Idaho National Engineering Laboratory. It analyses the thermal-hydraulic behavior of light water reactor system subject to postulated transients such as those resulting from loss of coolant, pump failure, or nuclear power excursions.

EDSFLOW considers a thermal and hydraulic system as a series of interconnecting user-detined or control volumes. The program solves the mass and energy balances for volumes which contain one-dimensional homogenous fluid (water and steam) with the vapor and liquid phases in thermodynamic equilibrium. The momentum transport equation is solved at the interf aces or junctions between the control volumes. The code requires specific input in order to solve the conservation equations for both the modeled volume contents and the connecting junctions. Additional input is required to described component models which affect the mass, momentum, and energy balances.

l The fluid dynamics portions of EDSFLOW solves the fluid mars, energy, and flow equations for the system being modeled.

In order to provide a reasonable degree of versatility, a choice of the following basic forms of the flow equation is provided:

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l NORTHERN STATES POWER COMPANY Main $teamline Tunnel MONTICELLO NUCLEAR GENERATION PLANT Temperature Switches 01-0910-1151 Rev. 2 Page A-3

1. Compressible single-stream flow with l

I momentum flux.

l.

2. Compressible two-stream flow with one-dimensional momentum mixing.

3. Incompressible single-stream flow without momentum flux.

The compressible two-stream flow equation has four forms to represent different flow patterns of the streams. The fluid system to be analyzed by EDSFLOW must be specified by the user and is modeled by fluid volumes and junctions (flow paths) between volumes. Fluid volumes (control volumes) are used to represent the fluid in the system piping, plenums, reactor core, pressurizer, and heat exchangers. Any fluid volume may be chosen independently to represent a region of the system associated with a heat sink or source, such as fuel rods or a heat exchanger. The fluid volumes are connected by junctions which are used to transfer fluid into and out of fluid volumes. Options are available for selecting pump, valve, and bubble-rise models.

A heat-conductor model is used to transfer heat to or from the fluid in a fluid volume. The geometry and conditions of the heat :enductor are specified by the user.

Several options are also available for describing heat exchangers.

\i NORTHERN STATES POWER COMPANY Main Steamline Tunnel MONTICELLO NUCLEAR GENERATION PLANT Temperature Switches 01-0910-1151 Rev. 2 Page A-4 The main assumptions in EDSFLOW are:

1. The thermal-hydraulic equations used in EDSFLOW are based on the fundamental assumption that a two-phase fluid is homogenous and that the phases are in thermal equilibrium.

2. Multidimensional flow paths are approximated with one-dimensional equations.

3. The air assumed to be a perfect gas with a constant specific heat.

4. The EDSFLOW containment option allows the description of air flow along, or in combination with single or two-phase water flow. A homogenous equilibrium j ' model is used in the sonic velocity j calculation of air-steam-water mixtures.

5. The junction enthalpy is normally approximated as the average enthalpy upstream of the junction, as modified l

by the bubble-rise model. ,

6. The heat-conduction model'used to l account for the heat transfer to and from the fluid in given volumes is based on a one-dimensional numerical solution of heat-conduction equations.

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