ML112970874

Proposed Amend to License DPR-22,changing Tech Specs in Areas of Surveillance,Reactor Protection Monitoring Sys,Jet Pump Surveillance,Organization & Steam Line Area Temp Switch Deviation

ML112970874
Person / Time
Site:	Monticello
Issue date:	09/24/1982
From:	Musolf D Northern States Power Co
To:
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ML112970873	List: ML112970872 ML112970874 ML20065E212
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NUDOCS 8210010041
Download: ML112970874 (70)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION NORTHERN STATES POWER COMPANY MONTICELLO NUCLEAR GENERATING PLANT Docket No. 50-263 REQUEST FOR AMENDMENT TO OPERATING LICENSE NO. DPR-22 License Amendment Request Dated September 24, 1982 Northern States Power Company, a Minnesota corporation, request authorization for changes to the Technical Specifications as shown on the attachments labeled Exhibits A, B and C. Exhibit A describes the proposed changes along with reasons for the change. Exhibit B is a set of Technical Specification pages incorporating the proposed changes. Exhibit C is a detailed evaluation prepared for one of the requested changes.

This request contains no restricted or other defense information.

NORTHERN STATES POWER COMPANY By Z5 David Musolf Manager of Nuclear Support Servic s On this day of /,,

before me a notary public in and for said County, personally appeared David Musolf, Manager of Nuclear Support Services, and being first duly sworn acknowledged that he is authorized to execute this document on behalf of Northern States Power Company, that he knows the contents thereof and that to the best of his knowledge, information and belief, the statements made in it are true and that it is not.interposed for delay.

6210010041 820924 PDR ADOCK 05000263 P

PDR a

BETTYJ.DEAN 4OTAAY PUBLIC - MINNESOTA RAMSE COUNTY My-Commssion Emppres Dec to 1987

EXHIBIT A Monticello Nuclear Generating Plant License Amendment Request Dated September 24, 1982 Proposed Changes to the Technical Specifications Appendix A of Operating License DPR-22 Pursuant to 10 CFR 50.59 and 50.90, the holders of Operating License DPR-22 hereby propose the following changes to Appendix A, Technical Specifications:

1. Alternate Rod Injection PROPOSED CHANGE Revise the Technical Specifications on pages i, vi, 48, 60, 69, and 71 to reflect the installation in 1980 of Alternate (or ATWS) Rod Injection (ARI) at the Monticello Nuclear Generating Plant. Refer to Exhibit B.

REASON FOR CHANGE An ARI system was installed to provide diverse control blade injection which is motivated mechanically by the normal hydraulic control units and control rod drives, but which utilizes totally separate and diverse logic. The initiating signals of high vessel pressure (-<

1150 psig) or low-low water level are used to operate separate solenoid valves which cause the pilot air header to bleed down. This feature increases scram reliability by approximately one order of magnitude.

Since ARI.uses the same logic as the Recirculation Pump Trip system, the necessary Technical Specification changes simply extend the requirements established for the Recirculation Pump Trip logic to ARI also.

SAFETY EVALUATION The effects of ARI in conjunction with the Recirculation Pump Trip system in mitigating the consequences of an ATWS event have been analysed and found acceptable as reported in General Electric Topical Report NEDO.25016, "Evaluation of Anticipated Transients Without Scram for the Monticello Nuclear Generating Station." Additional modifications may be required as a result of rulemaking now in progress.

EXHIBIT A

-2

2. Section 4.0. Surveillance Requirements PROPOSED CHANGE Add a new section 4.0 as shown on page 25a of Exhibit B. This change will clarify the permissible tolerance on surveillance testing frequency and specify those plant conditions during which surveillance testing can be suspended and when it must be resumed. The existing Technical Specifications do not address these issues.

REASON FOR CHANGE The requested wording is identical to wording approved several years ago for our Prairie Island Nuclear Generating Plant. The new Section 4.0 will set specific limits on variances in the surveillance schedule and clarify those conditions under which the tests may be suspended (e. g. during outages when the equipment is not required to be operable) and when they must be re sumed (if possible, prior to placing the plant in a condition which requires the equipment to be operable).

SAFETY EVALUATION The proposed wording generally conforms to existing practice and meets the.

intent of the Commission's Standard General Electric Boiling Water Reactor Technical Specifications.

EXHIBIT A

-3

3. RPS Power Monitoring System PROPOSED CHANGE Add new Limiting Conditions for Operation and Surveillance requirements for the new RPS power monitoring system.

Refer to page.27-in Exhibit B.

REASON FOR CHANGE General Electric Electrical Protection Assemblies (EPA's) have been installed in each of the three possible power supplies for the reactor protection system. This installation was described in earlier correspondence. The proposed changes conform to NRC Staff guidance contained in a letter dated July 28, 1982 from Domenic B Vassallo, Chief, Operating Reactors Branch

1. 2, to D H Musolf, NSP.

SAFETY EVALUATION The new EPA's and their associated Technical Specification requirements provide assurance that RPS power sources will be tripped when outside the voltage and frequency ranges for normal operation. As noted in earlier correspondence, the Monticello installation meets all General Electric and NRC requirements for this modification.

4. Shutdown Cooling Supply Isolation PROPOSED CHANGE Add Limiting Conditions for Operation and Surveillance Requirements for the shutdown cooling system supply isolation logic. Refer to Exhibit B, pages 50, 62, and 70.

REASON FOR CHANGE This change is being submitted at the request of our Project Manager in the Division of Licensing. This isolation feature is not included in the current Monticello Technical Specifications.

SAFETY EVALUATION This change will establish Limiting Conditions for Operation and Surveillance Requirements for this isolation logic. Since this circuitry has been tested for many years (non-Technical Specification required surveillance),

this change simply formalizes operability and surveillance requirements.

Specified setpoints and allowable deviation are based on existing setpoints and a reasonable allowance for instrument error. The maximum permissible isolation setpoint of 100 psig is well below the design pressure of the shutdown cooling system supply piping.

/

a. Page 4

b. Page 71

c. Page 90

d. Pages.179 and 180

e. Page 227c

f. Page 230

g. Page'238

h. Page 241 Change "Atomic Energy Commission" to "Commission" in item (V)..

Change the indicated Table number to Table 3.2.7 Supply missing portions of the definition of Ni Correct the bases to reflect the removal of two vacuum breakers.

Refer to Amendment 8 to DPR-22 dated November 5, 1981.

Revise the Table as indicated to show the larger number of detectors actually installed and the location correction.

Revise the description in Section 5.3 of the reactor vessel construction codes and standards to correct an inconsistency between the current wording and the FSAR.

The FSAR is correct and should be referenced.

Change "AEC" to "Commission" in Section 6.2.A.5.a.

Change "FSAR" to "Updated Safety Analysis Report" in Section 6.2.B.4.b.

REASON FOR CHANGE The specified corrections are self-explanitory.

SAFETY EVALUATION None required.

1 EXHIBIT A

-4

5. Miscellaneous Typographical Errors and Clarifications PROPOSED CHANGE Correct the following errors. Refer to the appropriate.

Exhibit B page for the correction:

EXHIBIT A

- 5

6. Specification 3.6.G, Jet Pumps PROPOSED CHANGE Revise Specifications 3.6.G and 4.6.G and the associated-bases to reflect the latest General Electric Guidance on jet pump operability and surveillance requirements.

Refer to pages 128 and 153 in Exhibit B.

REASON FOR CHANGE The Monticello operation surveillance procedures have been modified to include the recommended jet pump monitoring procedures in General Electric Service Information Letter (SIL) 330.

SAFETY EVALUATION The proposed revision updates this section of the Technical Specifications in accordance with the latest guidance from General Electric. The proposed surveillance program provides additional assurance that jet pump degradation will be detected prior to actual jet pump failure.

7. Specifications 3.6/4.6.H, Snubber Surveillance PROPOSED CHANGE

a. Revise Specification 4.6.H.3 to read "...at least once per Operating Cycle..." instead of "...at least once per 18 months + 25%...."

b. Add additional snubbers to Table 3.6.1. Refer to Exhibit B, Pages 131, 132, and 132a.

REASON FOR CHANGE Change (a) is needed since the originally approved wording (Amendment 9'to DPR-22 dated December 28, 1981) does not permit testing at intervals less than 18 months -

25%.

It's clear that a minus tolerance should not have been applied to this testing.

The proposed change, to simply once per cycle, removes this difficulty.

Change (b) adds snubbers to the surveillance program.

These snubbers were installed as part of the Mark I containment program modfications at the last maintenance outage.

SAFETY EVALUATION None required.

EXHIBIT A

-6 8.. Specification 3.7.A.4, Vacuum Breakers PROPOSED CHANGE Revise the Limiting Conditions for Operation to permit vacuum breaker cycling (i. e. opening, holding open for up to one minute, and closing) one vacuum breaker at a time during containment inerting and deinerting operations. Refer to Exhibit B, page.164.

REASON FOR CHANGE The proposed change: will alloaw-cycling of the drywell-wetwel vacuum breakers during inerting and deinerting operations to aid in changing the gas mixture in the drywell-torus vent pipes and vent header. This represents a substantial fraction of the total containment free volume. Without vacuum breaker cycling, oxygen remains in this volume following inerting operations and additional purging is required following return to service. Following shutdown, vacuum breaker cycling can help clear this area of nitrogen and eliminate potential pockets of inert gas.

SAFETY EVALUATION Cycling of drywell-torus vacuum breakers will be accomplished one at a time with an operator present at the test push-button. This operation is not much different than the monthly valve exercise test. If a vacuum breaker would stick open, the plant would be placed in cold shutdown as required by the existing Technical Specifications.

Inerting and deinerting operations rarely occur more than one to three times per year. The ability to purge the vent pipes and vent header in a more thorough manner is significantly improved if vacuum breakers are cycled.

9.. Specification 3.7.A.5, Containment Purge and Vent Operations PROPOSED CHANGE Revise Specification 3.7/4.7.A.5 as shown on Exhibit B pages 165, 166, and 171 to restrict purge and vent operations above cold shutdown to the 2-inch bypass flow path (except for inerting and deinerting) and require valve seal replacement at least once each five year period.

REASONS FOR CHANGE These.changes implement the Commission's established position on containment purge and vent operations during normal operation. Refer to our letter dated January 20, 1982.

SAFETY EVALUATION These changes provide additional assurance that the containment purge and vent valves will close as required if a containment pressurization accident occurs during purge or vent operations.

EXHIBIT A 7

10. Table 3.7.1. Prinary Containment Isolation PROPOSED CHANGES Revise Table 3.7.1 as shown in Exhibit B, page 172 to:

a. Show the correct normal position (open) of the recirculation loop sample valves

b. Clarify the specified normal position of the drywell and torus vent valves (certain valves are open to permit operation of the drywell-to torus d/p system).

REASON FOR CHANGE These changes correct the table to show the normal position of the recirc sample valves and add a clarifying note to the specified position of certain drywell and torus vent valves.

SAFETY EVALUATION None is required.

11. Specification 3.9, Additional Battery System PROPOSED CHANGE Revise.the station battery system Limiting Conditions for Operation and Surveillance Requirements to incorporate the new 250 VDC HPCI battery.

Refer to Exhibit B, pages 203 and 204.

REASON FOR CHANGE A new 250 VDC battery is being installed to supply auxiliary power for the HPCI system. This modification was.made to improve the plant electrical separation in the event of fire and is described in Supplement No. 1 to the NRC Fire Protection Safety Evaluation Report for Monticello dated February 12, 1981. The proposed changes will add appropriate Limiting Conditions for Operation and Surveillance Requirements for-the new battery.

SAFETY EVALUATION HPCI and RCIC systems will receive power from separate 250 VDC systems following this change. This will result in an improvement in the ability of the plant to cope with severe fires in certain parts of the plant.

Refer to the Monticello Appendix R safe shutdown analysis submitted on June 30, 1982 for further information.

3.0 LIMITING CONDITIONS FOR OPERATION 4.0 SURVEILLANCE REQUIREMENTS The representative sample selected for functional 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 functional test shall be retested during the next test period if they were reinstalled as a safety-related snubber.

If a spare snubber 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 (i.e. frozen in place) the cause shall be evaluated and if caused by manufacturer or design deficiency, all snubbers of the same design subject to the same defect shall be functionally tested.

130a REV I

3.6/4.6

3. Functional testing of snubbers shall be 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 a bench test.

For each snubber that does not meet the functional test acceptance criteria in Specification 4.6.H.4 below, an additional ten percent of that brand shall be functionally tested until no more failures are found or all snubbers of that brand have been tested.

TABLE 3.6.1 SAFETY RELATED'HYDRAULIC SNUBBERS SNUBBER NO.

SYSTEM LOCATION ELEVATION AZIMUTH ACCESSIBLE

-A (AIRLOCK 0 REF)

INACCESSIBLE-1 P--------------------------------------------------------H2 MAIN-ST-AM-DRYWELL-953---------------------------------------------------

PSI-H3 MAIN STEAM DRYWELL 953 071 PS2-H3 MAIN STEAM ORYWELL 950 148 I

PS2-HZ MAIN STEAM DRYWELL 950 120 I

PS3-H3 MAIN STEAM DRYWELL 950 240 I

PS4-H3 MAIN TEAM DRYWELL 9S0 212 RV24-H3 SAFETY-RELIEF DRYWELL 950 110 RV24-H4 SAFETY-RELIEF DRYWELL 935 100 RV24-H4A SAFETY-RELIEF DRYWELL 935 100 RV24-HS SAFETY-RELIEF DRYWELL 935 110 RV24-NSZ SAFETY-RELIEF ORYWELL 934 081 RV24-NS3 SAFETY-RELIEF DRYWELL 962 090 RV24-NH SAFETY-RELIEF DRYWELL 9S 090 RV24A-H4A SAFETY-RELIEF DRYWELL 947 048 I

RV24A-H7 SAFETY-RELIEF DRYWELL 9S3 088 I

RV24A-HS SAFETY-RELIEF ORYWELL 939 032 I

RV24A-NS2 SAFETY-RELIEF DRYWELL 952 050 I

RV24A-NS2 SAFETY-RELIEF ORYWELL 952 055 I

RV24A-N1 SAFETY-RELIEF ORYWELL 956 086 I

RV25-HI SAFETY-RELIEF ORYWELL 953 180 I

RV2S-HIA SAFETY-RELIEF DRYWELL 953 180 I

RV2S-H2 SAFETY-RELIEF DRYWELL 948 190 I

RV2S-H2A SAFETY-RELIEF ORYWELL 948 190 RV2S-H3 SAFETY-RELIEF DRYWELL 934 180 I

RV25-NS2 SAFETY-RELIEF DRYWELL 952 160 RV2S-N53 SAFETY-RELIEF ORYWELL 952 195 RV2S-NH3 SAFETY-RELIEF DRYWELL 921 158 I

RV2SA-H2 SAFETY-RELIEF DRYWELL 945 120 I

RV25A-H2A SAFETY-RELIEF DRYWELL 945 120 RV25A-H7 SAFETY-RELIEF DRYWELL 953 135 RV2SA-NS2 SAFETY-RELIEF DRYWELL 934 110 I

RV2SA-NS3 SAFETY-RELIEF DRYWELL 952 122 1

RV26A-NS SAFETY-RELIEF DRYWELL 953 12 I

RV26-HI SAFETY-RELIEF ORYWELL 953 200 I

RV26-HIA SAFETY-RELIEF ORYWELL 947 200 I

RV26-H2 SAFEJY-RELIEF ORYWELL 947 200 I

RV26-HA SAFETY-RELIEF ORYWELL 947 200 I

RV26-NH SAFETY-RELIEF DRYWELL 956 200 I

RVZ6A-H2 SAFETY-RELIEF DRYWELL 940 250 RV26A-H2A SAFETY-RELIEF ORYWELL 935 240 I

RV26A-NS1 SAFETY-RELIEF DRYWELL 934 240 RV26A-NS2 SAFETY-RELIEF DRYWELL 934 230 RV26A-NS3 SAFETY-RELIEF ORYWELL 920 257 I

AV26A-N2 SAFETY-RELIEF DRYWELL 950 250 RV26A-N2 SAFETY-RELIEF DRYWELL 951 20 RV27-HI SAFETY-RELIEF DRYWELL 950 20 I

RV27-HIA SAFETY-RELIEF DRYWELL 950 230 I

RV27-HS SAFETY-RELIEF DRYWELL 94S 270 1

3.6/4.6.

131 REV

TABLE 3.6.1 SAFETY RELATED HYDRAULIC SNUBBERS SNUBBER NO.

SYSTEM LOCATION ELEVATION AZIMUTH ACCESSIBLE

-A (AIRLOCK 0 REF)

INACCESSIBLE-1 RV27-H6 SAFETY-RELIEF ORYWELL 945 270 I

RV27-NSI SAFETY-RELIEF ORYWELL 934 250 1

RV27-NSZ SAFETY-RELIEF DRYWELL 934 280 RV27-N1 SAFETY-RELIEF ORYWELL 956 270 I

RV27A-H2A SAFETY-RELIEF DRYWELL 953 290 I

RV27A-H3 SAFETY-RELIEF DRYWELL 953 290 RV27A-H9 SAFETY-RELIEF DRYWELL 938 290 RV27A-NSI SAFETY-RELIEF ORYWELL 952 282 RV27A-NS2 SAFETY-RELIEF DRYWELL 952 279 RV27A-NS3 SAFETY-RELIEF ORYWELL 952 282 RV27A-N1 SAFETY-RELIEF DRYWELL 956 270 R26-NSI SAFETY-RELIEF DRYWELL 952 200 I

SS-1 MAIN STEAM DRYWELL 953 279 I

SS-1AR RECIRCULATION DRYWELL 922 315 SS-1BR RECIRCULATION DRYWELL 922 135 I

SS-11 FEEDWATER ORYWELL 952 302 1

55-12 FEEDWATER DRYWELL 952 058 I

55-13 FEEDWATER DRYWELL 952 258 I

55-14 FEEDWATER DRYWELL 952 096 I

SS-17A RHR DRYWELL 964 072 I

55-178 RHR DRYWELL 964 072 1

SS-18A RHR DRYWELL 964 288 I

55-183 RHR DRYWELL 964 288 I

S-19 RHR ORYWELL 964 341 I

SS-2 MAIN STEAM DRYWELL 953 081 1

SS-2AR RECIRCULATION DRYWELL 927 302 I

SS-28R RECIRCULATION DRYWELL 927 122 I

ss-20 RHR DRYWELL 964 019 I

SS-3 MAIN STEAM DRYWELL 950 212 I

SS-3AR RECIRCULATION DRYWELL 927 328 I

SS-38R RECIRCULATION DRYWELL 927 148 I

SS-4 MAIN STEAM DRYWELL 950 148 I

SS-4AR(A)

RECIRCULATION DRYWELL 934 302 I

SS-4AR(B)

RECIRCULATION DRYWELL 934 323 I

SS-4ErR(A)

RECIRCULATION ORYWELL 934 120 I

SS-4BR(B)

RECIRCULATION DRYWELL 934 149 I

SS-40 HPCI MAIN STEAM CHASE I

SS-SAR RECIRCULATION DRYWELL 941 315 1

SS-SBR RECIRCULATION DRYWELL 941 135

.1 55-6AR RECIRCULATION DRYWELL 953 261 I

5S-6BR RECIRCULATION DRYWELL 953 099 I

55-7 MAIN STEAM ORYWELL 953 240 I

55-7AR RECIRCULATION DRYWELL 953 323 1

SS-7BR RECIRCULATION DRYWELL 953 032 I

SS-8 MAIN STEAM ORYWELL 953 120 I

SS-8AR RECIRCULATION DRYWELL 927 270 I

SS-6BR RECIRCULATION DRYWELL 927 090 I

3.6/4.6 132 REV

TABLE 3.6.1 SAFETY RELATED HYDRAULIC SNUBBERS 5NUBBER NO.

SYSTEM LOCATION ELEVATION AZIMUTH ACCESSIBLE

-A (AIRLOCK 0 REF)

INACCESSIBLE-I 55-21 RHR TORUS FL LV -

S WALL A

SS-23 RHR TORUS FL LV -

S WALL A

SS-23 RHR B RHR ROOM FL LV A

SS-24 RHR A RHR ROOM FL LV A

55-25 RHR TORUS CATWK-SE WALL A

S5-26 CORE SPRAY B RHR ROOM FL LVL A

55-27 CORE SPRAY B RHR ROOM FL LVL A

SS-28A CORE SPRAY A RHR ROOM FL LVL A

55-28B CORE SPRAY A RHR ROOM FL LVL A

SS-29 RHR OVER N2 ANALYZER 954 A

SS-30 RHR OVER N2 ANALYZER 954 A

SS-31 RHR TORUS CATWK A

SS-32A RHR A RHR ROOM -

BY HX 916 A

SS-32B RHR A RHR ROOM -

BY HX 916 A

SS-33 RHR ABOVE TORUS A

SS-34 RHR ABOVE TORUS A

SS-35 HPCI HPCI ROOM -

N WALL 912 A

SS-36A HPCI HPCI ROOM -

FL LVL A

55-36B HPCI HPCI ROOM -

FL LVL A

SS-37 HPCI HPCI ROOM -

W WALL 905 A

SS-38A RCIC RCIC ROOM -

W WALL 906 A

SS-38B RCIC RCIC ROOM -

W WALL 906 A

ES-41 CORE SPRAY ABOVE TORUS CATWK 927 A

55-42 HPCI ABOVE TORUS RING HDR 906 A

3.6/4.6 132a REV

ME2IBIT A

-8 12.. Specifications 6.1 and 6.2, Organizational Changes PROPOSED CHANGE

'Revise the Section 6.1 and 6.2 Technical Specifications to reflect details of the recent NSP organizational changes. Refer to Exhibit B, pages 233, 234, 235, 239, and 240.

REASON FOR CHANGE Recent changes have occurred to improve management control and support of NSP's nuclear generating plants. The creation of a Production Training Department with training centers at each plant (including a simulator by 1984) greatly improves the quality and quantity of training services.

The new position of Director Nuclear Generation centralizes in one management position all responsibilities for NSP's nuclear facilities.

The requested changes correct the Technical Specifications by changing the reporting level for the training manager and specifying "Director Nuclear Generation" in place of "Vice President Power Production" where it appears.

SAFETY EVALUATION None is required.

13.

Specification 6.5. Plant Operating Procedures PROPOSED CHANGE Refer to Exhibit B, pages 244 and 244a (new page).

These changes:

a. Remove emergency plan drill requirements from the Technical Specifications and correct the title of the plan.

b. Provide an expanded Radiation Protection Program requirement and limit the extent of required Operations Committee review of radiation protection procedures.

REASON FOR CHANGE Change (a) reflects the new emergency planning regulations (Appendix E) which contain current drill requirements.

Change (b) is needed to accompany our revised Radiation Protection Program.

The scope of this program precludes detailed Operations Committee review of all procedures.

SAFETY EVALUATION Drill requirements will be as specified in the Commission's regulations.

Operations Committee review of radiation protection procedures will be omitted only for non-safety related procedures associated with activities performed exclusively by health physics personnel.

EXHIBIT A

-9

14. Table 3.2.7. High Temp in Main Steam Line Tunnel, Allowable Deviation PROPOSED CHANGE Increase the allowable deviation in the trip setting of the steam line tunnel high temperature switches to +100 F. Refer to Exhibit B, page 70.

REASON FOR CHANGE The present allowable deviation is too low. There have been recurring reportable occurrences due to main steam line area temperature switch set-point drift. Lowering the "as left" setpoint to allow for this drift is not possible due to high temperatures in this area. The existing switches have proven to be extremely reliable,.and the drift is not considered excessive in this application.

To justify an increase in the "as-found" setpoint for these switches, EDS Nuclear, Inc. was asked to perform a temperature profile analysis of the steam tunnel area for a steam line break. The results of this work are contained in Exhibit C. An increase in the allowable deviation from +2oF to +10OF is shown to be acceptable.

SAFETY EVALUATION Refer to Exhibit C.

EXHIBIT 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 changes.

Pages vi 4

25a (new page) 27 48 50 60 62 69 70 71 90 128 129 130a 131 132 132a 153 164 165 166 171 172 179 180 203 204 227c 230 233 234 235 238 239 240 241 244 244a (new page) 245 6210010046 820924 PDR ADOCK 05000263 P

PDR

TABLE OF CONTENTS Page 1.0 DEFINITIONS 2.0 SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS 2.1 and 2.3 Fuel Cladding Integrity 2.1 Bases 2.3 Bases 2.2 and 2.4 Reactor Coolant System 2.2 Bases 2.4 Bases 3.0 LIMITING CONDITIONS FOR OPERATION AND 4.0 SURVEILLANCE REQUIRENTS 4.0 Surveillance Requirements 3.1 and 4.1 Reactor Protection System 3.1 Bases 4.1 Bases 10 14 21 22 24 25a 25a 26 35 41 3.2 and 4.2 Protective Instrumentation A.

Primary Containment Isolation Functions B.

Emergency Core Cooling Subsystems Actuation C.

Control Rod Block Actuation D. Air Ejector Off-Gas System E.

Reactor Building Ventilation Isolation and Standby Gas Treatment System Initiation F.

Recirculation Pump Trip and Alternate Rod Injection Initiation 3.2 Bases 4.2 Bases 3.3 and 4.3 Control Rod System A. Reactivity Limitations B. Control Rod Withdrawal C.

Scram insertion Times D.

Control Rod Accumulators E.

Reactivity Anomalies F.

Required Action 3.3 and 4.3 Bases REV 1

6 6

45 45 46 46 46 48 48 64 72 76 76 77 81 82 83 83 84 1

LIST OF TABLES Table No.

Pge 3.1.1 Reactor Protection System (Scram) Instrument Requirements 28 4.1.1 Scram Instrument Functional Tests - Minimum Functional Test Frequencies for Safety Instrumentation and Control Circuits 32 4.1.2 Scram Instrument Calibration -

Minimum Calibration Frequencies for Reactor Protection Instrument Channels 34 3.2.1 Instrumentation that Initiates Primary Containment Isolation Functions 49 3.2.2 Instrumentation that Initiates Emergency Core Cooling Systems 52 3.2.3.

Instrumentation that Initiates Rod Block 57 3.2.4 Instrumentation,that Initiates Reactor Building 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 60a 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 Instrumentation 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 Maximum Average Planar Linear Heat Generation Rate vs. Exposure 214 3.14.1 Instrumentation for Accident Monitoring 229b 4.14.1 Minimum Test and Calibration Frequency for Accident Monitoring Instrumentation 229c 6.1.1 Minimum Shift Crew Composition 236 REV vi

4.

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

R. Rated Ueutron Flux - Rated flux is the neutron flux that corresponds to a steady-state power level of 1670 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 Refuling Outage - Refueling Operation is any operation when the reactor water temperature is less than 212? 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.

5. 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 operation.

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

1.04

.0 REV

3.0 LIMITING CONDITIONS FOR OPERATION 4.0 SURVEILLANCE REQUIREMENTS 4.0 SURVEILLANCE 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 B and C below.

B. Specific time intervals between tests may be adjusted plus or minus 25% to accomodate 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.

25a REV 3.0/4.0

3.0 LIMITING CONDITIONS FOR OPERATION 4.0 SURVEILLANCE REQUIREMENTS B.

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

1. Satisfy the minimum requirements by 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 Ionitoring System

1. Except as specified below, both channels of the power monitoring system for the MG set or alternate source supplying each reactor protection system bus shall be operable with the following setpoints:

a.

b.

c.

Over-voltage Under-voltage Under-frequency 5128 VAC 104 VAC 557 HZ

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 MG set or alternate power supply from service.

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 remove the associated RPS MG set or alternate power supply from service.

3.1/4.1 B. Once per day during power operation the MFLPD (Maximum Fraction of Limiting Power Density) shall be checked and the scram setting given by the equation in Specification 2.3.A shall be adjusted if necessary.

C. RPS Power Monitoring System

1. Instrument Functional Tests of each RPS power monitoring channel shall be performed at least once every six months.

2. At least once each Operating Cycle an Instrument Calibration of each RPS power monitoring channel shall be performed to verify over-voltage, under-voltage, and under-frequency setpoints.

27 REV 4

3.0 LIMITING CONDITIONS FOR OPERATION 4.0 SURVEILLANCE REQUIREMENTS E.

Reactor Building Ventilation Isolation and Standby Gas Treatment System Initiation

1. a. Except as specified in 3.2.E.L.b below, four radiation monitors shall be operable at all times..

b. One of the two monitors in the venti lation plenum and one of the two radia 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 ventilation system shall be iso lated and the standby gas treatment system operated until repairs are complete.

2.

The radiation monitors shall be bet to trip as follows:

(a) ventilation plenum 1: 3 mr/hr (b) refueling floor

-100 mr/hr

3.

When irradiated fuel is in the reactor vessel and the reactor water temperature is above 212 0 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

1. Whenever the reactor is in the RUN Made, the limiting-conditions for operation for the instrumentation listed in Table 3.2.5 shall be met.

48 3.2/4.2 REV

TABLE 3.2.1 - Continued Min. No. of Operable Total No. of Instru-or Operating Instru ment Channels Per ment Channels Per Trip Required Function Trip Setting.

Trip System System (1,2)

Conditions

b. High Drywell Pressure

'(5)

3. Reactor Cleanup System (Group 3)

a. Low Reactor Water Level

b. High Drywell Pressure

4. 1PCI Steam Lines

a. IIPCI High Steam Flow

b.

11PCI High Steam Flow

c. IIPCI.steam Line Area High Temp.

5. RCIC Steam Lines

a. RCIC High Steam

b.

RCIC Steam Line Flow Area 6.. Shutdown Cooling Supply Isolation

a. Reactor.Pressure Interlock

< 2 ps ig

> 10'6" above the top of the active fuel

< 2 paig

<150,000 lb/hr with <60 second time delay

<300,000 lb/hr

<200o0F

<45,000 lb/hr

<2000F 75 psig at pump suction 2

2 2

2(4) 2(4) 16(4) 2(4) 16(4) 2(4) 50 REV 3.2/4.2

Table 3.2.5 Instrumentation that Initiates a Recirculation Pump Trip and Alternate Rod Injection Minimum No. of Oper linimum No. of able or Operating Operable or Total No. of instru-Instrument Channels Required operating Trip ment Channels Per Per Trip System Conditions*

Function Trip Setting Systems (1)

Trip System

()

1. High Reactor Dome Prehsure

!S 1150 psig 2

2 2

A

2.

Low Reactor Water Level 6' 6" above the top of the active fuel.

2 2

2 A

NOTE:

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 condition, or

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

• Required conditions when minimum conditions for operation are not satisfied:

A.

Reactor in Startup, Refuel or Shutdown mode.

60 3.2/4.2 REV I

Table 4.2.1 - Cont inued Hinilmu Telst and Calibration Frequency For Core Cooling lad Black &and isolation Inatraentation Instreu"ent Channel Test (3)

Calibration (3)

Sensor aseck (3)

3. Steas 1.1n. Lou Pressulre Note I Once/I months None

4.

iteam Line hil1 Ralletlion Once/week (5)

Hate 6 oce/lift 1PC[ ISOLATION

3.

Steas Line High vluw Onca/month Once/) months None

2.

Steam Line High Temperatare Once/saontlh Once/

months ise ACIC ISOLATION

1. Steam Line High Flou Once/month Once/

month.

None

2.

Steam Line High Temperature Hate I Once/) aonthe None NEACTOR bill.DIGHO VENTIAI.TION

1.

Radistilon Hanitore (Plenu.)

Hote I Coce/) montise Once/shift

2.

Radiet loss Ianitors (Befueling Floor)

Niate I Once/

soalis (4)

OFF-CAS ISOLATION

1. Madiation Hountiore (Air Ejectors)

Hotes (5a Hote 6 Once/shift REClutilATION 1H'1P TRIP I.

Reactor High Pressure IHate I Once/Operating Cycle-Oce/Day Transmiltter OCe)

Honaths-Trip Unit

2.

teactor LoW wlater Level (ute

1)

Once/nonth Once/operating Cycle-Oncelahift Transaltter 1ocell Ionthe-Trip thAs SHUTDOWN COOLING SUPPLY ISOIATION

1. Reactor Pressure Interlock Note 1 Once/3 months None 62 REV 3.2/4.2

Bases Continued:

increases core voiding, a negative reactivity feedback.

High pressure sensors initiate the pump trip in the event of an isolation.transient.

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 after 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 system.

Two solenoid valves are installed in the scram air header upstream of the hydraulic control units. Each of the two trip systems energizes a-valve to vent the header and causes rod insertion. This greatly reduces the long term 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 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 point, ect. Therefore, these deviations have been accounted for in the various transient analyses and-the actual trip settings may vary by the following amounts.

69 3.2 BASES REV

Table 3.2.7

• Trip Functione And Deviations Trip Function Deviation Reactor aillding Ventilation Isolation and Ventilation Plenum 0.2 Mr/Hr Standby Gas Treatment System Initiation Radiation Monitors 8pecification 3.2.E.3 and Table 3.2.4 Refueling Flbor Radiation Monitors

+5 Mr/Hr Low Reactor Water level

-6 inches High Drywell Pressure

+ 1. pat Primary Contaiment Isolation Functions Table 3.2.1 Low Low Water level High Flow in Main Steam Eine High Temp. in Main Steam Eine Tunnel Low Pressure in Main Steam LUne High Drywell Pressure low Reactor Water Level HPCI High Steam Flow HPCI Steam Une Area High bp.

RCIC High Steam Flow kCIC Steam Line Area High Temp Shutdown Cooling Supply Iso

-3 inches

+2 %

+10 0 F I

-10 psi

+1 psi

-6 inches

+7,500 lb/hr

+2oF

+2250 lb/hr

+2oF

+25 psi I

70' REV 3.2 BASES

Table 3.2.q - Continued Trip Function and Deviations Trip Function Instrumuntation That Initiates Emergency Core Cooling Systems Table 3.2.2 Low-Low Ruactor Water Level Reactor Low Pressure (Pump Start) Parmasive High Drywall Pressure Low Reactor Pressure (Valve Permissive)

Instrumentation That Initiates IRM Downscale

-2/125 of Scale Rod iloick IR Upscale

+2/125 of Scale Table 3.2.3 APRil Downscale

-2/125 of Sate APRII Upscale See Basis 2.3 RON Downscale

-2/125 of Scale RHMI Upscale Same as APRH Upscale scram Discharge Volume-iigh

+ 1 gallon Level InStinmentation That Initiates High Reactor Pressure

+ 12 pat Recirculattun Puimp Trip and Low Reactor Water Level

-3 Inches Alternate Rod Iniection A violation of this specification Is assumed to occur only when a device to knowingly set outside of the IImitinig trip settings, or, when a atiffictent number of devices have been affected by any means such that the unstomatic function is incapable of operating within the allowable deviation while in a reactor mode in Wh1ich the specified fuinction Must ha operable or when actions specified are not Initiated as specified.

J.2 ISASES 11 REV Deviation

-3 Inches.

-10 pat

1. 1 pst

-10 pai

Bases Continued 3.3 and 4.3; The analysis assumes 50 milliseconds for Reactor Protection System delay, 200 milli seconds from de-energization of scram solenoids to tie beginning of rod motion, and 175 milliseconds later the rods are at the 5% position.

Section 3.3.C.3 allows a lower HCPR limit to be used if the cycle average scram time (T,

) Is less than the adjusted analysis mean scram time (l') (see Reference 7, of Section 3.11)

%,j is the weighted cycle average scram time to the rods pieasured at any point in the cycle.

20% insertion position (-notch 38) of all tie operable I'

N(4 i-I Ni is the adjusted analysis wean scram time to tie 20% insertion position.

To -

0.710 4 0.0875 N

n where:

n m the number of surveillance tests performed to date in this cycle.

Ni -

number of control rods measured in tie ith test.

Ir

- average scram time to the 20% insertion position of all rods measured in tihe ith test.

where:

N

- total number of active rods measured in the first test following core alterations.

0.710 tie mean scram time used In the analysis.

0.0875 - 1.65x0.053 where 1.65 is the appropriate statistical number to provide a 95%

confidence level and, 0.053 is time standard deviation of the distribation for average scram insertion time to the 20% position, that was used in the analysis.

3.3/4.3 BASES I

90 REV

3.0 LIMITING CONDITIONS FOR OPERATION F.

(Deleted)

G. Jet Pumps Whenever the reactor is in the Startup or Run modes, all jet pumps shall be operable with the requirement that each individual jet pump diffuser to lower plenum differential pressure (D/P) percent deviation from average loop D/P shall not differ by more than 20% deviation from its normal range of deviation.

With one or more jet pumps exceeding the stated criteria, evaluate the reason for the deviation, and in the circumstance that one or more of the jet pumps are determined to be inoperable, 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 />.

3.6/4.6 F. (Deleted)

G. Jet Pumps Whenever there is recirculation flow with the reactor in the Startup or Run mode, operating jet pumps shall be demonstrated Operable daily and following any unexplained change in core flow, jet pump loop flow, recirculation loop flow, or core plate differential pressure, by recording jet pump loop flows, recirculation pump flows, recirculation pump speeds, and individual jet pump D/P, and verifying that:

1. The recirculation pump flow/speed ratio deviation from normal expected operating range does not exceed 5%.

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

If either of these conditions are not met, determine individual jet pump D/P percent deviation from average loop DIP and compare to the Limiting Conditions for Operation.

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

128 REV 4

4.0 SURVEILLANCE REQUIREMENTS 3.0 LIMITING CONDITIONS FOR OPERATION 4.0 SURVEILLANCE REQUIREMENTS H. Snubbers

1. Except as permitted below, all snubber.

listed in Table 3.6.1 shall be operable above Cold Shutdown. Snubbers may be inoperable in Cold Shutdown and Refueling Shutdown whenever the supported system is not required to be Operable.

2. With one or more snubbers made or found to be inoperable for any reason when Operability is required, within 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />s:

a. Replace or restore the inoperable snubbers to Operable status and perform an engineer ing evaluation or inspection of the supported components, or

b. Determine through engineering evaluation that the as-found condition of the snubber had no adverse effect on the supported components and that they would retain their structural integrity in the event of the design basis seismic event, or

c. Declare the supported -system inoperable and take the action required by the Technical Specifications for inoper ability of that system.

H.

Snubber.

The following surveillance requirements apply to all snubbere listed in Table 3.6.1.

1. Visual inspection of snubbers shall be conducted in accordance with the following schedule:

No. of Snubbers Found Inoperable per Inspection Period 0

2 3,4 5,6,7 8 or more Next Required Inspection Period 18 months + 25%

12 months ; 25%

6 months + 25%

124 days + 25%

62 days ; 25%

31 days + 25%

The required inspection interval shall not be lengthened more than one step at a time.

Snubbers may be categorized in two groups, "accessible" or "inaccessible" based on their accessibility for inspection during reactor operation. These two groups may be inspected independently according to the above schedule.

3.6/4.6 129 REV

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.

Core Flow versus Square Root of Core Plate Differential Pressure:

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.

If resistance decreases, less speed is needed.

2.

Recirculation Pump Flow/Speed Ratio: the pump operating characteristic is determined by the flow resistance from the loop suction through the jet pump nozzle.

Since this resistance is essentially independent of core power, the flow is linearly proportional to pump speed, making their ratio a constant (flow/RPM is constant).

A decrease in the ratio indicates a plug, flow restriction, or loss in pump hydraulic performance.

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

3.

Jet Pump Loop Flow/Recirculation Pump Speed Ratio:

this relationship is an indication of overall system performance.

4.

Jet Pump Differential Pressure Relationships:

if a potential problem is indicated, the individual jet pump differential pressures are used to determine if a problem exists since this is the most sensitive in dicator of significant jet pump performance degradation.

3.6/4.6 153 REV

3.0 LIMITING CONDITIONS FOR OPERATION 4.0 SURVEILLANCE REQUIREMENTS

4. Pressure Suppression Chamber-Drywell Vacuum Breakers

a. When primary containment is required, all drywell-suppression chamber vacuum breakers shall be operable and positioned in the closed position as indicated by the position indication system, except during testing and except as specified in 3.7.A.4.b through 3.7.A.4.d below.

b.

Any drywell-suppression chamber vacuum breaker may be nonfully closed as indicated by the position indication and alarm systems provided that drywell to suppression chamber differential pressure decay does not exceed that shown on Figure 3.7.1.

c. Up to two drywell-suppression chamber vacuum breakers may be inoperable provided that: (1) the vacuum breakers are determined to be fully closed and at least one position alarm circuit is operable or (2) the vacuum breaker is secured in the closed position.

d.

Drywell-suppression chamber vacuum breakers may be cycled, one at a.'

time using the exercise test push button, during containment inerting and deinerting operations to assist in purging air or nitrogen from the suppression chamber vent header.

4. Pressure Suppression Chamber-Drywell Vacuum Breakers

a. Operability and full closure of the drywell-suppression chamber vacuum breakers shall be verified by performance of the following:

(1)

Monthly each operable drywell suppression chamber vacuum breaker shall be exercised through an opening-closing cycle.

(2)

Once each operating fuel cycle,.

drywell to suppression chamber leakage shall be demonstrated to be less than that equivalent to a one-inch diameter orifice and each vacuum breaker shall be visually inspected.

(Containment access required)

(3) Once each operating cycle, vacuum breaker position indication and alarm systems shall be calibrated and functionally tested.

(Containment access required)

(4) Once each operating cycle, the vacuum breakers shall be tested to determine that the force required to open each valve from fully closed to fully open does not exceed that equivalent to 0.5 psi acting on the suppression chamber face of the valve disc. (Containment access required) 164 REV 3.7/4.7 I

a ITUvr 1rA%1TTTf~cZ FOR OPE~RATION 4.0 SURVEILLANCE REQUIREMENTS

d. one position alarm circuit can be inoperable providing that the redundant position alarm circuit is operable. Both position alarm circuits may be inoperable for a period not to exceed seven days provided that all vncuum breakers are operable.

Containment Atmosphere Control

a.

The primary containment atmosphere shall be reduced to less than 5% oxygen with nitrogen gas whenever the reactor is in 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 52 by weight, and maintaine 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.

3.7/4.7

b. When the position of any drywell suppression chamber vacuum breaker valve is indicated to be not fully closed at a time when such closure is required, the drywell to suppression chamber differential pressure decay shall be demonstrated to be less than that shown on Figure 3.7.1 imediately 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 a.Whenever inerting is required, the primary containment oxygen concentration shall be measured and recorded on a weekly basis.

165 REV 52 1/9/81 I

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 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 with 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 />.

B. Standby Gas Treatment System

1. Two separate and independent standby gas treatment system circuits shall be operable at all times when seconcary containment integrity is required, except as specified in sections 3.7.8.1.(a) and (b).

a. After one of the standby gas treatment system circuits is made or found to be inoperable for any reason, reactor operation and fuel handling is permissible only during the succeeding seven days, provided that all active components in the other standby gas treatment system shall be demonstrated to be oper 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).

3.7/4.7 S

B. Standby Gas Treatment System

1. At least once per month, initiate from the control room 3500 cfm (+10%) flow through both circuits of the standby gas treatment system.' In-addition:

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 standby gas treatment system circuit is made or found to be inooerable for any reason and daily thereafter for the next succeeding seven days, initiate from the control room 3500 cfm (+10%)

flow through the operable circuit of the standby gas treatment system.

166 REV

3.0 LIMITING CONDITIONS FOR OPERATION 4.0 SURVEILLANCE REQUIRENENTS

2.

In the event any isolation valve specified in Table 3.7.1 becones inoperable, reactor operation in the run mode may continue provided at least one valve in each line having an inoperable valve is closed.

3. If Specification be met, initiate and have reactor condition within 3.7.D.1 and 3.7.D.2 cannot normal orderly shutdown in the cold shutdown 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

c.

At least once per quarter-Continued (2) With the reactor power less than 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 and subsequent reopening.

2. Whenever an isolation valve listed in Table 3.7.1 is inoperable, the position of at least one fully closed valve in each line having an inoperable valve shall be recorded daily.

3. The isolation valves listed in Table 3.7.1 shall be'demonstrated Operable prior to returning the valve to service after maintenance, repair, or replacement work is performed on the valve or its associated actuator, control, or power pircuit by performance of a cycling test and verification of operating time.

4. The valve seals of the drywell and suppression 18-inch purge and vent valves shall be replaced at least once every five years.

171 REV 3.7/4.7 A

TABLE PRIMARY CCNTAINM4E4ET ISOLATION Isolation Valve Number of Group Identification Valves Maximum Operating Normal Inboard Outboard Time (Sec)

Positicn 1

Main Steam Line Isolation 4

4 3

T 5

Open 1

Main Steam Line Drain 1

1 60 Closed 1

Recirculation Loop Sample Line 1

1 60 Open 2

Drywell Floor Drain 2

60 Open 2

Drywell Equipment Drain 2

60 Open 2

Drywell Vent 2

60 Closed 2

Drywell Vent Bypass 1

60 Closed 2

Drywell Purge Inlet 2

60

• Open 2

Drywell and Suppression Chamber 1

60 Closed Air Makeup 2

Suppression Chamber to Drywell 1

60

• Open N2 Recirculation 2

Suppression Chamber Vent 2

60 Closed 2

Suppression Chamber Vent Bypass 1

60

• Open 2

Shutdown Cooling System 1

1 120 Closed.

• Open to maintain drywell-torus differential pressure.

This differential pressure removed and the valves will be normally closed following completion of the Mark I long term program modifications.

3.7/4.7 will be containment 172 REV

'1 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 seat.

The position indication system is designed to detect 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 is conservatively designed to demonstrate that leakage iks less than that equivalent to leakage through a one-inch orifice which is about 3% of the maximum allowable. This test is planned to establish a baseline for valve performance at the start of each operating. cycle and to ensure that vacuum breakers are maintained as nearly as possible to their design condition. This test is not planned to serve as a limiting condition for operation.

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 closing fully through the position indication system. If one or more of the vacuum breakers do not seat fully as determined from the indicating system, a leak test will be conducted to verify that leakage is within the maximum allowable.

Since the extreme lower limit of switch detection capablitty 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. During the first refueling outage all ten vacuum breakers were shimmed 1/16 open at the bottom of the disc.

The bypass area associated with the shimming corresponded to 63 of the maximum allowable.'

The results of this test are shown in Figure 3.7. 1.

Two'of the original ten vacuum breakers have since been removed.

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 Green -

On 2 Red Off*

Intermediate Position 2 Green -

Off 2 Red Off Full Open 2 Green -

Off 2 Red

- On The remote testpanel consists of a push button to actuate the air cylinder for testing, two red lights.

179 3 EV 3.7 BASES

Bases Continued:

and two green lights for each of the eight valves.

There are fourirrdependent limit switches on each valve.

The two switches controlling the green lights are adjus.ed to provide an indication of dis opening of less than 1/"

at the bottom of the disc.

These swftches are also used to activate the valve position alarm circuits.

The two switches controlling the red lights are adjusted to provide indication of the disc very near the full open position.

The control room alarm circuits are redundant and fail safe. This assures that no simple failure will defeat alarming to the control room when a valve is open beyond allowable and when power to the switches fails. The alarm is needed to alert the operator that action must be taken to correct a malfunction or to investigate possible changes in valve position status, or both.

If the alarm cannot be cleared due to the inability to establish 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 testing of the alarms is the same as that required for the position Indication system.

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 considered inoperable and a pressure test is required immediately and upon indication of subsequent operatimn.

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

The 5% oxygen concentration minimizes 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 refueling outage or other scheduled shutdown is more probable than the occurrence of the loss of 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 terms of the added plant safety offered without significantly reducing the margin of safety. Thus, to preclude the possibility of starting the reactor and operating for extended periods of time with significant leaks in the primary system, leak inspections are scheduled during startup periods, when the primary system is at or near rated operating temperature and pressure.

The 24-hour period to provide inerting is judged to be sufficient to perform the leak inspection and establish the required oxygen concentration. The primary containment is normally slightly pressurized during periods of reactor operation.

Nitrogen used for inerting could leak out of the containment but air could not leak in to increase oxygen concentration.

Once the con tainment is filled with nitrogen to the required concentration6 no monitoring of oxygen concentration is necessary. However, at least once a week the oxygen concentration will be determined as added assurance.

3.7 BASES 180 REV

3.0 LIMITING CONDITIONS FOR OPERATION 4.0 SURVEILLANCE REQUIREMENTS

4. Station Battery System If one of the two 125 V battery systems or one of the two 250 V battery systems* is made or found to be inoperable for any reason, an orderly shutdown of the reactor shall be initiated and the reactor water temperature shall be reduced to less than 212 0 F 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

5. 24V Battery Systems From and after the date that one of the two 24V battery systems is made or found to be inoperable for any reason, refer to Specifi caton 3.2 for appropriate action.

• Applicable only to single station 250 V battery until completion of plant modification adding second 250 V battery (1983).

4. Station Battery System

a. Every week the specific gravity and voltage of the pilot cell and temperature of the adjacent cells and overall battery voltage shall he measured.

b. Every three months the measure ments shall be made of voltage of each cell to nearest 0.01 volt, specific gravity of each, cell, apd temperature of every fifth cell.

c.

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

Determine specific gravity and voltage of each cell after the discharge.

5. 24V Battery Systems

a. Every week the specific gravity and voltage of the pilot cell and tempera ture of adjacent cells and overall battery voltage shall be measured.

b. Every three months the measurements shall be made of voltage of each cell to nearest 0.01 volt, specific gravity of each cell, and temperature of every fifth cell.

203 REV 3.9/4.9

Bases 3.9:

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

AC for shutdown requirements and operation of engineered safeguards equipment can be provided by either of two active and 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 reserve truns formers.

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.

The plant's main generator Is not given credit as a source since it is not available during shutdown.

The plant 250 V dc 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 dc requirements with the batteries as a standby source during emergency conditions. The plant 125 V dc power is normally supplied by two batteries, each with an associated charger.

Backup chargers are available.

The minimum diesel fuel supply of 26,250 gallons will supply one diesel generator for a minimum of 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.

In the normal mode of operation, power Is available from the off-site sources.

One diesel may be allowed out of service based on the availability of off-eite power and the daily testing of the remaining diesel generator.

Thus, though one diesel generator is temprarily out of service, the off-site sources are available, as well as the remaining diesel generator.

Dased on a monthly testing period (Specification h.9), the seven day repair period Is justified.

(1)

(1)

"Reliability of Engineered Safety Features as a Function of Testing Frequency", I. M. Jacobs, Nuclear Safety, Volume 9, No. It, July - August 1968.

204

3. 9 RASEs REV

TABLE 3.13.1 SAFETY RELATED FIRE DETECTION INSTRUMENTS Location "B" RHR Room "A". RHR Room RCIC Room HPCI Room Reactor Reactor Reactor Reactor Reactor Reactor Reactor Reactor Reactor Reactor Building-Torus Compartment Bldg. 935' elev -

TIP Driv Bldg. 935' elev

" CRD HCU Bldg. 935' elev -

CRD HCU Bldg. 935' - LPCt Injectio Bldg. 962' elev -

SBLC Are Bldg. 962' elev -

South Bldg. 962' elev -

RBCCW Pu Bldg. 985' elev -

South Bldg. 985' elev -

RBCCW lx Instrumenta Flame e Area Area East Area West n Valve Area a

mp Area Area Fire Zone IA IB IC IE IF 2A 2B 2C 2E 3B 3C 3D 4A 4B 4D 5A 5B SC 6

7A 7B 7C 8

12A 13C 14A 15A 15B 16 17 19A 19B 19C 20 23A 3.13/4.13 Turbine Bldg.

Turbine Bldg.

Turbine Bldg.

1. 12 DG Room &

1. 11 DG Room &

Turbine Bldg.

Turbine Bldg.

Turbine Bldg.

Turbine Bldg.

Turbine Bldg.

911' 4.16 KV Switchgear 911' elev -

MCC 133 Area 931' -

4.16 KV Switchgear Day Tank Room Day Tank Room 931' elev -

Cable Corridor 941' elev -

Cable Corridor 931' elev - Water Treatment Area 931' elev -

HCC 142-143 Area 931' elev -

FW Pipe Chase Heating Boiler Room Intake Structure Pump Room Minimum Heat SBGT System Room Reactor Bldg. 1001' elev -

South Reactor Bldg. 1001' elev -

North Reactor Bldg. -

Fuel Pool Cooling Pump Area Reactor Building 1027' elev Battery Room Battery Room Battery Room Cable Spreading Room 4

Operable Smoke 3

3 3

2 11 10 11 1

2 5

.4 4

5 2

7 3

1.

5 I

1 1

7 3

1 2

3 3

5.

I I

3 3

3 1

227c 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 Mionesota State Grid, South Zone.

The nearest site boundary is approximately 1630 feet S 300 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 fuel assemblies.

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.

5.3 Reactor Vessel A. The pressure vessel shall be designed for a pressure of 1250 paig and a temperature of 5750F.

The coolant recirculation system shall be designed for a pressure of t148 psig on suction side of pump and 1248 paig at pump discharge.

The applicable design codes shall be as described in 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 ibsorption chamber constructed of steel.

The drywell shall have a volume of approximately 134,200 ft and is designed to conform to ASHE Boiler and Pressure Vessel Code Section III Class B for an internal pressure of 56 psig at 2810F and an external pressure of 2 pa g at 281 0 F. The absorption chamber shall have a total volume of approximately 176,250 ft 5.0 230 REV

E. A training program for individuals serving in the fire brigade shall be maintained under the direction of a designated member of Northern States Power management.

This program shall meet 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.

g 6.1 233 REV

ON-SITE TRAINING I

I I

I I

ON-SITE TECHNICAL SERVICES GROUPS SAC ADMINISTRATION I

L AUDIT & REVIEW OF-HAS TiE RESPONSIBILITY FOR THE FIRE PROTECTION PROGRAM FIGURE 6.1.1 NSP CORPORATION ORGANIZATION RELATIONSHIP TO ON-SITE OPERATING ORGANIZATION, 6.1 234 REV 4

C00Es KEY SUPERVISOR LO LICENSED OPERATOR LSO LICENSED SENIOR OPERATOR FIGURE 6.1.2 MONTICELLO NUCLEAR GENERATING PLANT FUNCTIONAL ORGANIZATION FOR ON-SITE OPERATING GROUP 235 REV

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

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

4. Quorum

a.

No less than a majority of the permanent members-or their alternates, including the SAC Chairman or Vice Chairman..

b.

No more than n minority et -lie quorum' shall be from groups holding line responsibility for the operation of the p1lan.t.

5. Responsibilities -

The foilowing subjects ahoutlI he reported to or reviewed by the SAC:

a. Written safetd ovatuatifl-zif (3) changes in the facility, (2) changes to procedures, and (3) tests or txperivients completed withouL prior Commission approval under the provisions of 10 CFR 50.59 to verity that such changes, tests or experiments did ot involve a change in the Appendix A Technilcal Specifications or an unreviewed safety question as defined in 10 CFR 50.59.

b. Proposed changes to procedures, changes in the facility, and tests and experiments bhich may involve a chapoge in tie Appendix A technical specifications or an unreviewed safety quescion as afined in 10 eFR 50.59.

Matters of this kind shall be referred to the SAC following their rev!eue b!

the onsite operating organization.

c.

Proposed changes in Appendix A Technical Specifications or proposed licenso amendments relating to nuclear safety.

d. Violations of applicable codes, regulation, orders, Appendix A Technical Specifications, and license requirements or itterital proceduresi or instruciLloils having nuclear safety significance.

e. Significant operating abnormalities or deviations from normal and expected performance of plant safety-related structures, systems, or components.

238 REV 6.2

f. Investigation of all events iAhich are required by regulation or technical specifications to be reported to NRC in writing 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 Committee minutes to determine if matters considered by that Committee involve unreviewed or unresolved safety questions.

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

J.

All recognized indications of an unanticipated deficiency In some aspect of design or operation of safety-related structures, systems, or components.

k.

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

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

a. Audits of selected aspects of plant operation, as delineated In Paragraph 4.4 of ANSI N18.7-1972, shall be performed with a frequency commensurate with their nuclear safety significance 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 and procedures.

b. Periodic review of the audit program should be performed 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 REV

7. Authority The SAC shall be advisory to the Director Nuclear Generation.

8. Records Minu.tes shall be prepared and retained for all scheduled meetings of the Safety Audit Committee. The minutes shall be distributed within one month of the meeting to the Director Nuclear Generation, the General Manager Nuclear Plants, each member of the SAC, and others designated by the Chairman or Vice Chairman.

There shall be a formal approval of the minutes.

9. Procedures A written charter for the SAC shall be prepared that containes

a. Subjects within the purview of the group.

b. Responaibility and authority of the group.

c. Hechanisms for convening meetings.

d. Provisions of use of specialists or subgroups.

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

E.

Requirements for distribution of reports and minutes prepared by the group to others in the HSP Organization.

240 6.2 REV I-0

B.

Operations Committee (DC)

1. Membership lte Operations Committee shall consist of at least six (6) members drawn from the key super visors of the on-site supervisory staff.

The Plant Manager shall serve as Chairman of the 0C and shall appoint a Vice Chairman from the OC membersip to act in his absence.

2. Heeting Frequency The Operations Committee 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 Committee:

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.

c. Proposals which would effect permanent changes to normal and emergency operating procedures and any other proposed changes or procedures that are determined by the Plant Manager to affect nuclear safety.

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

e.

All reported or suspected violatlons of Technical Specifications, operating license requirements, administrative procedures, or operating procedures.

Results of investi gations, Including evaluation and recommendations to prevent recurrence, will be reported, in writing, to the General Manager Nuclear Plants and to the Chairman of the Safety Audit Committee..

241 REV 6.2

6.5 Plant Operating 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 Committee and approved by a member of plant management designated by the Plant Manager.

A. Plant Operations I. Integrated and system procedures for normal startup, operation 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 potential or actual malfunction of systems or components including responses to alarms, primary system leaks and abnormal reactivity changes gnd incipding follow-up actions required after plant protective system actions have Initiated.

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 emergency condditions*involving potential or actual releases of radioactivity.

7.

Implement Ing procedures of the fire protection program.

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

244 6.5

B. Radiological l.a. A Radiation Protection Program, 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 (2) Procedures which implement the requirements of the Radiation Protection Plan The Radiation Protection Plan and implementing procedures, with the exception of those non-safety related procedures governing work activities exclusively applicable to or performed by health physics personnel, shall be reviewed by the Operations Committee and approved by a member of plant management designated by the Plant Manager.

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 individuals 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.

6.5 244a REV

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 #s low as practical levels.

This program shall include the following:

a.

Provisions establishing preventive maintenance and periodic visual inspection require ments, and

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

3.

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

a. Training of personnel,

b. Procedures for monitoring, and

c. Provisions for maintenance of sampling and analysis equipment.

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

1979, from L 0 Mayer,

NSP, to Director of Nuclear Reactor Regulation, "Lessons Learned Implementation".

245 6.5 REV

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 Prepared by:

EDS Nuclear Inc.

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

Page i EDS NUCLEAR INC.

REPORT APPROVAL COVER SHEET Client: NORTHERN STATES POWER CO Project: MONTICELLO ENVIRONMENTL 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.

0 The work described in this Report was performed In accordance with the EDS Nuclear Quality Assurance Program. The signatures below verify the accuracy of this Report and its compliance with applicable ality assurance requirements.

Prepared By:

Date:

(

t Benjamin R. Strong, Seniol Technical Specialist, SED Reviewed By:

Date:

Lawrence J. Metalfe, ising Engineer, SED Approved By:

Date:

-3 Timothy K. Snyder, Manager, Systems Engineering Division REVISION RECORD

0 NORTHERN STATES POWER COMPANY MONTICELLO NUCLEAR GENERATION PLANT TABLE OF CONTENTS Main Steamline Tunnel Temperature Switches 01-0910-1151 Rev. 2 Page ii Report Approval'Cover Sheet Table of Contents 1.0 Introduction 2.0 Scope 3.0 Method of Analysis 3.1 Assembly and Review of Input Data 3.2 Computer Analysis 4.0 Results and Conclusions 5.0 References Appendix A:

EDSFLOW Computer Program Description Page ii 1-1 2-1 3-1 3-1 3-2 4-1 5-1 I

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

1.0 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

!S 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.

O

NORTHERN STATES POWER COMPANY MONTICELLO NUCLEAR GENERATION PLANT Main Steamline Tunnel Temperature Switches 01-0910-1151 Rev. 2 Page 2-1 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 2-121B TS 2-121C TS 2-121D TS 2-123A TS 2-123B TS 2-123C TS 2-123D TS 2-122A TS 2-122B TS 2-122C TS 2-122D TS 2-124A TS 2-124B TS 2-124C TS 2-124D 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.

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

2 Page 3-1 3.0 METHODS OF ANALYSIS 3.1 ASSEMBLY AND REVIEW OF INPUT DATA A break on the order of 5 to 10 gpm in the 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.

Heat 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 blow out panel in main steamline tunnel would not be affected by this event.

The engineering analysis includes:

a. Assembly and review of input data

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

The following sections describe each task in more detail.

The information relevant to the main steamline tunnel area, including layout, 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.

b. System conditions.

c. Operations reports on MSTS function.

NORTHERN STATES POWER COMPANY MONTICELLO NUCLEAR GENERATION PLANT 3.2 COMPUTER ANALYSIS Main Steamline Tunnel 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 temperature 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).

Based on a postulated break in the main 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.

I

NORTHERN STATES POWER COMPANY MONTICELLO NUCLEAR GENERATION PLANT 3.2.1 COMPUTER MODEL DESCRIPTION 3.2.2 HEAT STRUCTURE MODELING Main Steamline Tunnel 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.

The computer program EDSFLOW was used to model the main steamline tunnel. EDSFLOW is the EDS Nuclear proprietary version of the RELAP4/MOD5 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 represents 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.

It was necessary to model heat-conducting 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.

NORTHERN STATES POWER COMPANY MONTICELLO NUCLEAR GENERATION PLANT 3.2.3 FLOW PATH MODELING 3.2.4 BLOWDOWN FLUID PROPERTIES Main Steamline Tunnel Temperature Switches 01-0910-1151 Rev. 2 Page 3-4 Normal junctions between volumes such as 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 psid (Reference 1).

The fluid properties in the main steamline 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.

'I.

f

1 4

NORTHERN STATES POWER COMPANY MONTICELLO NUCLEAR GENERATION PLANT Main Steamline Tunnel Temperature Switches 01-0910-1151 Rev. 2 Page 3-5 FIGURE 3-1 EDSFLOW COMPUTER MODEL EL 958.6 HVAC 6

INLET FLOW 7

HEAT TRANSFERRED FROM PROCESSED FLUID K

O PORTION OF MST CONTAINING TEMPER ATURE SWITCHES AND MAIN STEAMLINES 1ST

-E LOWER PORTION OF MST

-E 3

L.

943' 5

i f EAMLINE LEAK L.

935' O -

VOLUME 1 2

X -JUNCTION 2

L.

931' EL. 957.5' UPPER PORTION OF MAIN STEAMLINE TUNNEL (MST) 2

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

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 212oF temperature will be reached with a 5 gpm main steamline leak.

During the most limiting winter conditions the analysis results show the 212oF temperature threshold is reached due to a 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.

The analysis conducted yielded the following conclusions:

1. Any setpoint, when added to the temperature switch deviation, totaling 212oF 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 3.2.6) may be revised by NSP to reflect this higher allowable temperature.

0 NORTHERN STATES POWER COMPANY MONTICELLO NUCLEAR GENERATION PLANT Main Steamline Tunnel 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 analyses would have to be performed to assess the adequacy of the temperature switches for those functions.

• 1 1

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

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

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. 52, 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. 5828.

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

NORTHERN STATES POWER COMPANY MONTICELLO NUCLEAR GENERATION PLANT Main Steamline Tunnel Temperature Switches 01-0910-1151 Rev. 2 Page A-2 APPENDIX A EDSFLOW COMPUTER PROGRAM DESCRIPTION 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 is a modified version of the RELAP4/MOD5 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-defined 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 interfaces 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.

The fluid dynamics portions of EDSFLOW solves the fluid mass, 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:

i 4

I

• g NORTHERN STATES POWER COMPANY Main 8teamline Tunnel MONTICELLO NUCLEAR GENERATION PLANT Temperature Switches 01-0910-1151 Rev. 2 Page A-3

1. Compressible single-stream flow with momentum flux.

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 conductor are specified by the user.

Several options are also available for describing heat exchangers.

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 model is used in the sonic velocity calculation of air-steam-water mixtures.

5. The junction enthalpy is normally approximated as the average enthalpy upstream of the junction, as modified by the bubble-rise model.

6. The heat-conduction model'used to 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.

4.