ML20088A619

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Proposed Tech Specs Changing Channel Calibr Frequency from Refueling (18 Months) to Annual (366 Days) for Radiation Monitoring Instrumentation Channels
ML20088A619
Person / Time
Site: Grand Gulf Entergy icon.png
Issue date: 04/07/1984
From:
MISSISSIPPI POWER & LIGHT CO.
To:
Shared Package
ML20088A618 List:
References
NUDOCS 8404120303
Download: ML20088A619 (38)
v • d • e


Text

{{#Wiki_filter:- 1. RADIATION MONITORING ISSUES A..(MP&L P/L Item No. 038)

SUBJECT:

Calibration Frequencies for Accessible Continuous Monitoring Radiation Instt. nts Technical Specification Surveillance Requirements Tab. 3 4.3.2.1-1, 4.3.7.1-1, 4.3.7.5-1, and s 4.3.7.12-1. DESCRIPTION The proposed changes to the Technical Specifications consists OF CHANGE: of changing the channel calibration frequency from " refueling" (18 months) to " annual" (366 days) for the following radiation monitoring instrumentation channels: 1. Table 4.3.2.1-1 (Pages 3/4 3-20 and 3-21) Item 1.g - Containment & Drywell Ventilation Exhaust a. b. Item 3.c - Fuel Handling Area Ventilation Exhaust c. Item 3.d - Fuel Handling Area Pool Sweep Exhaust 2. Table 4.3.7.1-1 (Page 3/4 3-59) a. Item 1 - Component Cooling Water b. Item 2 - Standby Service Water c. Item 3 - Offgas Pre-treatment

  • d.

Item 4 - Offgas Post-treatment

  • e.

Item 5 - Carbon Bed Vault f. Item 6 - Control Room Ventilation g. Item 7 - Containment and Drywell Ventilation Exhaust h. Item 8 - Fuel Handling Area Ventilation 1. Item 9 - Fuel Handling Area Pool Sweep Exhaust 3. Table 4.3.7.5-1 (Page 3/4 3-72) a. Item 14 - Containment Ventilation b. Item 15 - Offgas and Radwaste Building Ventilation c. Item 16 - Fuel Handling Area Ventilation d. Item 17 - Turbine Building Ventilation e. Item 18 - Standby Gas Treatment System A & B. Exhaust 4. Table 4.3.7.12-1 (Pages 3/4 3-92, 3-93, and 3-94) a. Item 1.s - Radwaste Building Ventilation (Noble Gas) b. Item 3.a - Containment Ventilation (Noble Gas) ' Item 4.a - Turbine Building Ventilation (Noble Gas) c. d. Item 5.a - Fuel Handling Area Ventilation (Noble Gas) e. Item 6.a - Offgas Pre-treatment (Noble Gas) f. Item 7.a - Offgas Post-treatment (Noble Gas) 3 A previous change request was submitted to the NRC to delete items 3 and 4 from this table.

Reference:

AECM-83/0565 from Mr. L. F. Dale to Mr. Harold R. Denton, dated September 9, 1983 (Item 2, GCNS-697, in that submittal). MP&L proposes to conform to the increased calibration frequency presented above for Items 2.c and 2.d until the previous change request for these items is acted upon by the NRC. 8404120303 840407 L/HI36cdal PDR ADOCK 05000416 P PDR

1. RADIATION MONITORING ISSUES (Continued) A; (MP&L P/L' Item No. 038) JUSTIFICATION: The Grand Gulf FSAR Section 11.5.2.3.2 states that continuous radiation monitoring instruments that are accessible during normal operation will be calibrated annually, and Section .) 12.3.4.2.7 states that airborne radiation monitors will be calibrated annually. In addition, the equipment vendors for the radiation monitors included in this change recommend an annual calibration frequency. Presently, all accessible radiation monitors listed in this change are calibrated annually in accordance with the Grand Gulf Surveillance Program. The proposed changes to the l Technical Specifications will require that-these monitors continue to be calibrated annually and will make the technical specification surveillance requirements consistent with both the FSAR and the vendor's recommendations. SIGNIFICANT' HAZARDS CONSIDERATION: The proposed changes to the Technical Specification Tables have been evaluated and determined to involve no significant hazard, as defined in 10 CFR 50.92. The changes have been proposed to render the Technical Specification surveillance frequencies consistent with the Grand Gulf FSAR and vendor recommendations. The proposed changes represent more stringent surveillance requirements in that they reduce the time interval between channel calibrations from that presently specified in the Technical Specifications. ..The proposed changes do not: 1. Involve a significant increase in the probability or consequences of an accident previously evaluated; or 1 2. Create the possibility of a new or different kind of accident from any accident previously evaluated; or 3. Involve a significant reduction in a margin of l_ safety. Therefore, the proposed changes do not involve a significant hazards consideration. i i t L/HI36cda2

1. RADIATION MONITORING ISSUES (Continued) B. (MP&L P/L Item No. 262)

SUBJECT:

Standby Gas Treatment System Exhaust Monitoring System. Technical Specification Tables 3.3.7.12-1, 4.3.7.12-1 and 4.11.2.1.2-1. DkSCRIPTION Revisions to Technical Specifications 3/4.3.7.12 and 3/4.11.2.1 0F CHANGE: -are proposed to specify additional requirements for Standby Gas Treatment System exhaust monitoring. 1. Tables 3.3.7.12-1 and 4.3.7.12-1 should be revised to include the Standby Gas Treatment System (SGTS) Exhaust Monitoring Systems A and B as part of the radioactive gaseous effluent monitoring instrumentation. (Pages 3/4 3-90, 3/4 3-91, and 3/4 3-94) 2. . Table 4.11.2.1.2-1 should be revised to include monthly grab samples of the SGTS A and B exhaust when the SGTS is discharging effluent. (Page 3/4 11-9) JUSTIFICATION: Currently the SGTS Exhaust Monitoring System is included in Technical Specification 3.3.7.5 for Accident Monitoring Instru- = mentation. The SGTS, however, may be operated for short periods of time for reasons other than the occurrence of an accident, (e.g. spurious initiation signals, SGTS surveillance testing and secondary containment integrity demonstrations). Since the SGTS provides a gaseous effluent release path when-ever it is in service, the inclusion of the SGTS Exhaust Monitoring System in the Gaseous Effluent Instrumentation Technical Specification 3/4.7.12 is appropriate. The minimum operable channel requirements, applicability requirements, action statements, and surveillance requirements proposed for Tables 3.3.7.12-1 and 4.3.7.12-1 are consistent with the design of the associated SGTS exhaust noble gas activity monitors. The addition of the SGTS exhaust to Table 4.11.2.1.2-1 will provide for inclusion of measurable SGTS exhaust contributions in the dose rate calculations if the SGTS has been run Implementation of the proposed changes will ensure that 3GTS Exhaust Monitoring System requirements are consistent with the intent of effluent monitoring requirements contained in 10 CFR 50 Appendix A Criterion 64. SIGNIFICANT HAZARDS CONSIDERATION: The proposed changes constitute an additional control not presently included in the Technical Specifications in that the operability and surveillance requirements for SGTS Exhaust Monitoring Systems are being expanded to ensure that the gaseous effluent monitoring requirements at Grand Gulf are L/HI42sdl

1. RADIATION MONITORING ISSUES (Continued) B. (MP&L P/L Item No. 262) consistent with 10 CFR 50 Appendix A, Criterion 64 requirements. As such, these proposed changes are not considered to: i e 1. Involve a significant increase in the probability or consequences of an accident previously evaluated; or 2. Create the possibility of an accident of a type different from any evaluated previously; or 3. Involve a significant reduction in a smrgin of safety. Therefore, the proposed changes to the Technical Specifications were determined to involve no significant hazards, as defined in 10 CFR 50.92. L/HI42sd2

TABLE 4.3.2.1-1 ISOLATION ACTUATION INSTRUE NTATION SURVEILLAACE REQUIREMENTS E CHAhMEL OPERATIONAL G CHANNEL FUNCTIONAL CHANNEL CONDITIONS IN WHICH Ij TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRE 0 1. PRIMARY CONTAllMENT ISOLATION a. Reactor Vessel Water Level - Low Low, Level 2 S M R 1, 2,'3 and # IC) 4. Reactor Vessel Water Level-S M R 1, 2, 3 and # Low Low, level 2 (ECCS - j Division 3) l IC) c. Reactor Vessel Water Level-5 M R 1, 2, 3 and #' i Low Low Low, Level 1 (ECCS - ], Division 1 and Division 2) lD d. Drywell Pressure - High 5 M R '1, 2, 3 iY IC) e. Drywell Pressure-High (ECCS - S M R 1, 2, 3 !5 Division 1 and Division 2) f. Drywell Pressure-High (ECCS - 5 M R(c) 1, 2, 3 l Division 3) g. Containment and Drywell Ventilation Exhaust I Radiation - High High S M

  • A 1, 2, 3 and
  • l I

M *) NA 1, 2, 3 and *#- h. Manual Initiation MA 2. MAIN STEAM LINE ISOLATION a. Reactor Vessel Water Level - i Low Low Low, Level 1 5 M R 1, 2, 3 } b. Main Steam Line Radiation - j High 5 M R 1,2,3 c.... Main Steam Line Pressure - } Low 5 M-R 1 d. Main Steam Line Flow - High S M R 1, 2,. 3 Condenser Vacuum - Low M R 1, 2**, 3** +

TABLE 4.3.2.1-1 (Continued) E h ISOLATION ACTUATION INSTRUENTATION SURVEILLANCE REQUIREMENTS 8 i CHANNEL OPERATIONAL i CHAMEL FUNCTIONAL CMMNEL CONDITIONS IN WHICH 5 TRIP FUNCTION CHECK TEST CAllBRATION SURVEILLANCE REQUIRED w 2. MIN STEAM LINE ISOLA 110N (Continued) g f. Main Steam Line Tunnel l Temperature - High M R 1, 2,' 3 g. Main Steam Line Tunnel I & Temp. - High S M R 1,2,3 M *) M 1,2,3 f I h. Manual Initiation M 3. SECONDARY CONTAIMENT ISOLATION l !l a. Reactor Vessel Water Level - Low Low, Level 2 5 M R 1, 2, 3 and # i I j b. Drywell Pressure - High 5 M R 1, 2, 3 c. Fuel Handling Area Ventilation j Exhaust Radiation - High High 5 M 4A 1, 2, 3 and * { i i d. Fuel Mandling Area Pool Sweep l Exhaust Radiation - High High S M +A 1, 2, 3 and

  • l M *I M

1, 2, 3 and

  • I e.

Manual Initiation M f r 1 l 4. REACTOR WATER CLEANUP SYSTEM ISOLATION l a. A Flow - High 5 M R 1,2,3 l b. A Flow Timer M M Q 1, 2, 3 t c. Equipment Area Temperature - High 5 M R 1,2,3 l d. Equipment Area Ventilation l a Temp. - High 5 M R 1, 2, 3 i e. Reactor Vessel Water l l Level - Low Low, Level 2 S M I, 2,. 3 i

TABLE 4.3.7.1-1 RADIATION IWIITORING INSTRUENTATION SURVEILLANdE REQUIREMENTS i ss OPERATIONAL E CHANNEL CONDITIONS FOR 1 7 CHANNEL FUNCTIONAL CHANNEL WHICH 54NtVEILLANCE j .g INSTRLMENTATION _ CHECK TEST CALIBRATION REQUIRED 2 1. Component Cooling Water Radiation Nonitor 5 M +A At all times 2. Standby Service Water System Radiation Monitor S M +A 1, 2, 3, and* i 3. Offgas Pre-treatment Radiation Monitor S M +A 1, 2 l 4. Offgas Post-treatment Radiation Monitor S M +A 1, 2 5. Carbon Bed Vanit Radiation Monitor 5 M 4A 1, 2 6. Control Room Ventilation Radiation M *I +A 1, 2, 3, 5 and*a I { Monitor S 7. Containment and Drywell Ventilation } Enhaust Radiation Monitor 5 M g 4.A At all times 8. Fuel Handling Area Ventilation i Y Radian. ion Monitor S M 4A 1, 2, 3, 5 and** 5 9. Fuel Handling Area Poni Sweep J Exhaust Radiation Monitor 5 M

  • -A (b) i
10. Area Monitors i

i a. Fuel Hand 11ng Area Monitors 1) New Fuel Storage Vault 5 M R (c) I 2) Spent Fuel Storag-I'c=1 0 R (d) 3) Dryer Storage Area 5 M R (e) b. Control Room Radiation Monitor 5 M R At all times With RHR heat exchangers la operation. 3 When irradiated fuel is being handled in the primary or secondary containment. 3 (a) The CHANNEL FUNCTIONAL TEST shall demonstrate that c'ontrol room annunciation occurs if any of the following conditions exist. 1. Instrument indicates measured levels above the alare/ trip setpoint. j 2. Circuit failure. i 3. Instrument indicates a downscale failure. { 4 Instrument controls not in Operate mode. 1 (b) With:frradiated fuel in the spent fuel storage pool. I (c) With fuel in the new fuel storage vault. (d) With fuel in the spent fuel storage pool. (e) With fuel in the dryer storage area. a

2 TABLE 4.3.7.5-1 ACCIDENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL CHANNEL INSTRUMENT CHECK CALIBRATION

1. ! Reactor Vessel Pressure M

R 2. Reactor Vessel Water Level M R 3. Suppression Pool Water Level M R 4. Suppression Pool Water Temperature M R 5. Drywell/ Containment Differential Pressure M R 6. Drywell Pressure M R 7. Drywell and Control Rod Cavity Temperature M R 8. Containment Hydrogen Concentration Analyzer and Monitor NA M* 9. Drywell Hydrogen Concentration Analyzer and Monitor NA M* 10. Containment Pressure M R 11. Containment Air Te,mperature M R 12. Safety / Relief VaTve Tail Pipe Pres sure Switch Position Indicators M R 2 13. Containment /Drywell Area Monitors M R** 14. Containment Ventilation Monitor M 4& A 15. Off gas and Radweste B1dg. Ventilation Monitor M ib A 16. Fuel Handling Area Ventilation Monitor M 4E A 17. Turbine B1dg. Ventilation Monitor M ib A 18. Standby Gas Treatment System A & B Exhaust Monitors M ib A

  • Using sample gas containing:

a. One volume percent hydrogen, remainder nitrogen. b. Four volume percent hydrogen, remainder nitrogen.

    • The CHANNEL CALIBRATION shall consist of an electronic calibration of the channel, not including the detector, for range decades above 10R/hr and a' one point calibration check of the detector below 10R/hr with an installed or portable gamma source.

GRAND GULF-UNIT 1 3/4 3-72

9 TABLE 3.3.7.12-1 (Continued) I RADIDACTIVE GASE0tl5 EFFill[NT MONITORING INSTRilMENTATION ,g 5 J: MINIMilM CHANNELS INSTRUMENT OPLRABLE APPLICABILITY ACTION y 6. OFFGAS PRE-TREATMENT MONITOR i l a. Noble Gas Activity Monitor 1 126 1 7. OFFGAS POST-TREATMENT MONITOR ' Noble Gas Activity Monitor a. Providing Alarm and Automatic ,)w Termination of Release 1 121 N8

6. STwaa y c,As TalATJef#7 EKMuST MeaseT1stnice SYSTEA CA rB)

A. W.&te. GA5 Ac.+ich Mwho 1/e==4 N 17.7 i I

TA8LE 3.3.7.12-1 (Continued) RADI0 ACTIVE GASE0US EFFLUENT MONITORING INSTRUMENTATION' TABLE NOTATION At all times.

  • During main condenser offgas treatment system operation.
      • ' During operation of the main condenser air ejector.

ACTION 121 - With the number of channels OPERABLE less than required by the Minnum Channels OPERA 8LE requirement, effluent releases via this pathway may continue for up to 30 days provided grab samples are taken at least once per 8 hours and these samples are analyzed for gross activity within 24 hours. ACTION 122 - With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, effluent releases via this pathway may continue for up to 30 days provided samples are continuously collected with auxiliary sampling equipment as required by Table 4.11.2.1.2-1. ACTION 123 - With the number of channels OPERABLE less than required by the Minimum Channels OPERA 8LE requirement, effluent release via this pathway may continue for up to 30 days provided the flow rate is estimated at least once per 8 hours. ACTION 124 - With the number of channels OPERABLE less than required by the Minimum Channels OPERA 8LE requirement, operation of main condenser offgas treatment system may continue for up to 30 days provided grab samples are collected at least once per 4 hours and analyzed within the following 4 hours. 1 ACTION 125 - [ DELETED] ACTION 126 - With the number of channels OPERABLE less than required by the Minimum Channels OPERA 8LE requirement, the SJAE effluent may be released to the environment for up to 72 hours provided: i a. The offgas system is not bypassed, except for filtration system bypass during plant startups, and b. The offgas delay system noble gas activity effluent i downstream monitor is OPERABLE; Otherwise, be in at least NOT STAN08Y within 12 hours. bCTsoN$2*l~ Ynn ,ne nurisaw w cnnun cas OlYM68.e Less 78nn Re mu snsa ony TNG Mouemun Cua n u ts.s OPre A ms.e sunevontrusa, E'Ffluz N T M E A r4 5< s VIA TNas Pm7HwAr 3Mai.u Have G rg43 Sn>teLas 'rA Ws N A r Lt Asi-o u e.a rese. e Hoons s y 7,4e i STANo sy gas rMr ATMENT S YS Tert a s N o pga a 7,,g. i AHo TNese SAM PLas s' HALL M A N AS.Y EGO rag Gg o s.s

  • l AC9sveTy WITHIN 2$ HQURS, GRAND GULF-UNIT 1 3/4 3-91

TABLE 4.3.7.12-1 h RA010ACilVE GASEOUS EFFtHENT MDNITORING INSTRUMENIAil0N SURVEILLANCE REQUlttfENTS l 5 E CNANNEL MODES IN WHICH CHANNEL SOURCE CHANNEL FUNCil0NAL SURVEILLANCE al INSTRLMENT CHECK CHECK CAllBRATION TEST REQUIRED 5 j 1. RA0 WASTE BUILDING VENillAil0N MONiiORING SYSTEM a. Noble Gas Activity Monitor l Providing Alarm D M A 4(3) Q(2) b. Iodine Sampler W N.A. N.A. N.A. c. Particulate Sampler W N.A. N.A. N.A. d. Flow Rate Monitor D N.A. R Q k k e. Sampler Flow Rate Monitor D N.A. R N.A. i 2. MAIM CONOENSER OFFGAS TREATMENT l' SYSTEM EXPLDS1VE GAS NONiiORING j SYSTEM a. Hydrogen Monitor D N.A. Q(4) M 3. CONTAINMENT VENTILAll0N MDN110 RING SYSitH i j a. Moble Gas Activity Monitor i Providing Alarm 0 M A-R(3) Q(2) j j b. Iodine Sampler W N.A. N.A. N.A. i i c. Particulate Sampler W N.A. M.A. N.A. l d. Effluent System Flow Rate Monitor D N.A. R Q e. Sampler flow Rate Monitor D N.A. R N.A.

c 4 I-_AR_ I E 4. 3. _1.12-1 (Co.n..t_.inued.). o ,h RADIDAC. TI.V..I G. ASFollS L F.ri.l.lf.M.T H.nN11.0.R..ING INSIRI.N.il N. T. A..ll0N S.liR.V. E E a CilANNEL MODES IN WillCll CilANNEL S0tlRCE CilANNEL filHCIlONAL SURVEILIAllCE 5, -INSIRilMENT C..l_ll_C.K_- ClifCK. cal lll.NAll0N II:SI R[l}lilRLD 4. IllRBINE Bl.DG. VENilLATION IlONITORING SYSitM a. Noble Gas Activity Monitor D M A.4t(3) Q(2) l i h. lodine Sampler W N.A. N.A. N.A. i c. Particulate Sampler W N.A. N.A. N.A. d. Flow Rate Monitor D N.A. R Q w D m e. Sampler Flow Rate Monitor D N.A. R N.A. h l S. FilEL llANDLING ARFA VENTILATION MONT0 RING SYSILM a. Noble Gas Activity Monitor D M A l -a(3) Q(2) h. lodine Sampler W N.A. N.A. N.A. c. Particulate Sampler W. N.A. N.A. N.A. ) d. Flow Rate Monitor D N.A. R Q 1 e. Sampler Flow Rate Monitor D N.A. R N.A. ) 1

TABLE 4.3.7.12-1 (Continised) NADISACTIVE GA5I005 EFFLUENT MONITORING INSTIR M NTATION SURVEILLANCE REqul N NTS E i G CHANNEL MODES IN WHICH j E CHANNEL SOURCE CHANNEL FUNCTIONAL SURVEILLANCE g INSTRUE NT _ CHECK _ CHECK CALIBRATION TEST REQUIRED 6. OFFGA5 PRE-TREATMENT MONITOR .i a. Noble Gas Activity Monitor D M A-A(3)" Q(2) \\ 1 7 Of FGAS P3ST-TREATENT MNITOR l a. Noble Gas Activity Monitor 1 Providing Alarm and Auto-I i matic Termination of Release D M A -A(3)N Q(1) I i Y t % STA#DSY (rM TAIATMa7T INNA4ST~ %#fra AWer Sysrs m (A+ 6) A WeLle. G 4s Asfio.}7 Mea.4er D M M3) Q(1) i I i i i -l

TABLE 4.11.2.1.2'-1 RADIOACTIVE GASEOUS WASTE SAMPLING AND ANALYSIS PROGRAM Minimum Type of Lower Limit Gdseous Release Sampling Analysis Activity of Detection Type Frequency Frequency Analysis (LLD) (pC1/ml)" D b -4 A. Containment M M Principa} Gamma 1x10 Ventilation Grab Sample Emitters Exhaust -6 H-3 1x10 b b Principa} Gamma! 1x10'4

8. Turbine Building M

g Ventilation GrabSamplej Emitters l Exhaust -6 H-3 1x10 Principa} Gamma! ~4 CA0ffgas Post Treatment M M 1x10 Exhaust, whenever Grab Sample Emitters _ there is flow d e -12 D. (1) Radwaste Building Continuous W I-131 1x10 Ventilation Charcoal i -10 l Exhaust Sample I-133 1x10 d e (2) Fuel Handling Continuous y Prin~cipa} Gamma 1x10'11 Area Ventila-Particulate Emitters tion Exhaust Sample (I-131,Others) d (3) Containment Continuous M Gross Alpha 1x10'11 Ventilation Composite Exhaust Particulate Sample d (4) Turbine Building Continuous Q Sr-89, Sr-90 1x10'11 Ventilation Composite Exhaust Particulate Sample Continuous Noble Gas Noble Gases 1x10'O I Monitor Gross Beta or Gamma ,, \\[ N st.ng r,.A+ A s.4.u., wk.u.c %,* e6 W

0) sw.aq c ww e a r,6...*, % /4 11-9

+ 8a = nA GRAND GULF-UNIT 1 3

l

2. (MP&L P/L Item No.103)

+

SUBJECT:

Main Steam Line Flow Minimum Operable Channel Requirements, Technical Specification Table 3.3.2-1 DESCRIPTION Revisions to Technical Specification Table 3.3.2-1 are proposed 0F CHANCE: to achieve consistency between the Technical Specifications and i plant trip logic design. 1. The number of main steam line (MSL) flow channels that are required to be operable in each trip system should be revised from two to eight. (Page 3/4 3-10) 2. Note (3) of Table 3.3.2-1 should be deleted as a result of implementing the above change. (Page 3/4 3-14a) 4 i JUSTIFICATION: In the Grand Gulf design, one of the signals that causes the main steam isolation and drain valves to close is high main steam line flow. The sixteen main steam line flow instrument channels are arranged into two trip systems, each containing I two channels per steam line for a total of eight channels per j trip system. The trip logic for both the main steam isolation valves and the main steam line drain valves, (i.e., the Group 1 i. isolation valves) is arranged such that all eight MSL flow channels in each trip system are required to be operable in order to meet single failure criteria. Both trip systems, each with eight channels operable, would close all MSIVs and the r associated drain valves performing isolation. The proposed change from two operable channels per trip system to eight, will ensure consistency between the Technical Specifications and plant trip logic design. ? i The implementation of the change in the number of operable MSL flow channels from two to eight will allow note (g) in Table 3.3.2-1 to be deleted. Note (3) is not consistent with MP&L's present definition for the terms " Channel", " Trip System", and r " Trip Function", (referenced in a letter to Mr. H.R. Denton of 4 the NRC from Mr. L.F. Dale of MP&L, dated December 15, 1983). The proposed change requires all MSL flow channels be operable, therefore no explanatory note is necessary. SIGNIFICANT HAZARDS CONSIDERATION: 4 The proposed changes will render the Technical Specifications consistent with plant design and MP&L's definition of the terms i "Channei", " Trip System" and " Trip Function". j MP&L considers the proposed changes to be conservative, in terms of safety, in that single failure criteria will be met for both MSL high flow trip systems. This constitutes a more stringent limitation than that presently required by the 4 Technical Specifications and therefore is not considered to (1) Involve a significant increase in the probability or consequences of an accident previously evaluated; or + 1 i I L/NI41ces!

(2) Create the possibility of a new or different kind of accident from any accident previously evaluated; or (3) Involve a significant reduction in a margin of safety. Thus, the proposed changes have been evaluated to involve no significant hazard, as defined in 10 CFR 50.92. L/N141cde2

TABLE 3.3.2-1 si ISOLATION ACTUATION INSTRUMENTATION I g VALVE GROUPS MINIMUM APPLICA8LE i q; OPERATED BY OPERA 8LE CHANNELS OPERATIONAL TRIP FUNCTION SIGNAL (a) PER TRIP SYSTEM (b) CONDITION ACTION i 1 E q 1. PRIMARY CONTAINMENT ISOLATION a. Reactor Vessel Water Level- ) Low Low, Level 2 64,7,8,10(c)(d) 2 1, 2, 3 and # 20 b. Reactor Vessel Water Level-Low Low Level 2 (ECCS - Olvisien 3) 68 4 1, 2, 3 and # 29 l c. Reactor Vessel Water Level-Low Low Low, Level 1 (ECCS - S,I 2 1, 2, 3 and # 29 I i Division 1 and Division 2) f g d. Drywell Pressure - High 6A, 7(c)(d) 2 1,2,3 20 l [ e. Drywell Pressure-High, (ECCS - Division 1 and 1 S ") '2 1,2,3 29 I j o Division 2) f. Drywell Pressure-High (ECCS - Division 3) 68 4 1,2,3 29 g. Containment and Drywell Ventilation Exhaust I2 ') 1, 2, 3 and

  • 21 Radiation - High High 7

h. Manual Initiation 64,7,8,10(c)(d) 2 1, 2, 3 and *# 22 2. MAIN STEAM LINE ISOLATION a. Reactor Vessel Water Level-Low Low Low, Level 1 1 2 1,2,3 20 j b. Main Steam Line j Radiation - High 1, 10(f) 2 1,2,3 23 J c. Main Steam Line i Pressure - Low 1 2 _1 24 d. Main Steam Line { Flow - High 1 NS 1, 2, 3 23 l 1 e. Condenser Vacuum - Low 1 2 1, 2,** 3*" 23 l L

~ _ _ _ _ - / . INSTRUMENTATION TABLE 3.3.5-1(Centinued) ~ ISOLAT]DN__ ACTUATION INSTRUMENTATION NOTES (Continued) (f) Also trips and isolates 'the rechanical vacuum pumps. (;) ^ :h=::P 1: OPEP,'"LE i' 2 ef-4 13:trnat; ir. ;ttet ;.'ar.ral ;re OP "." ALE. !=h tri; ty:t= =:t 5=: :t -h:s.t =; in:trz:.t p;r Ta'.. Ot; Lira I L'E"."2LE i ;r?;r ';r th: :h:=;1: to 5: ;;r.sidered 0" COLE. (h) Also actuates ' secondary containment ventiletion isolation dampers and 1 valves per Table 3.6.6.2-1. (1) Closes only RWCU system isolation valves G33-F001, G33-F004, and G33-F251. (j) Actuatas the' Stahdby Gas Treatment System and isolates Auxiliary Building penetration of the ventilation systems within the Auxiliary Building. (k) Closes only RCIC' outboard valves. A concurrent RCIC initiation signal is required for isolation to occur. (1) Valves E12-F037A and E12-F0378 are c % sed by high drywell pressure. All other Group 3 valves are closed by high reactor pressure. (m) Valve Group 9 requires concurrent drywell high pressure and RCIC Steam Supply Pressure-Low signals to isolate. (pt) Valves E12-F042A cnd E12-F0425 are closed by Centainment Spray System initiation signals. s i %e ? f 6 GRANDGULF-UHki1 3/4 3-14a

3. (MP&L P/L Items No. 292 and 293)

SUBJECT:

Containment and Drywell Air Lock Technical Specification Surveillance Requirements 4.6.1.3 and 4.6.2.3. DESCRIPTION Revisions to Technical Specification Surveillance Requirements OF CHANGE: 4.6.1.3 and 4.6.2.3 are proposed to ensure that adequate air lock door seal pressure is available when required. Technical Specification Surveillance Requirements 4.6.1.3.d.2 and 4.6.2.3.d.2 should be revised to require verification that the seal air flask pressure is greater than or equal to 90 psig rather than the currently required 60 psig. (Pages 3/4 6-6 and 3/4 6-16). ' JUSTIFICATION: To properly function, the containment and drywell air lock inflatable seals require a minimum of 60 psig air flask pressure. Technical Specifications 4.6.1.3.d.3 and 4.6.2.3.d.3 require verifying that the inflatable seal pneumatic system pressure decay rate is less than or equal to 2 psig in a 48 hour period, when starting with an initial pressure of 90 psig. Based on this allowable pressure decay rate and assuming a loss of air supply for 30 days, an initial seal air flask pressure of 90 psig is required to ensure that the containment and drywell seal air flask pressures remain above the minimum required value of 60 psig. The proposed change to the affected speci.fications clearly incorporates the 30 day leakage criteria into the surveillance requirement. SIGNIFICANT HAZARDS CONSIDERATION: The proposed changes to the Technical Specifications have been evaluated and determined to involve no significant hazard, as defined in 10 CFR 50.92. The changes made to the Surveillance Requirements are made to accurately reflect system design requirements and to ensure containment and drywell air lock inflatable seal integrity upon loss of seal air supply. The changes proposed constitute a more stringent limitation than is presently included in the Technical Specifications. The proposed changee do not: 1. Involve a significant increase in the probability or consequences of an accident previously evaluated, or 2. Create the possibility of a new or different kind of accident from any accident previously evaluated, or 3. Involve a significant reduction in a margin of safety. Therefore, the proposed changes do not involve a significant hazards consideration. L49sd1

u CONTAIMENT SYSTEMS SURVEILLANCE REQUIREMENTS 4.6.1.3 Each containment af r lock shall be demonstrated OPERABLE: Within 72 houri after each closing, except when the air lock is being a. used for multiple entries, then at least once per 72 hours, by verifying seal leakage rate less than or equal to 2 scf per hour when the gap between the door sealt'is pressurized to Pa, 11.5 psig. By conducting an overall air lock leakage test at P,w,11.5 psig, and b. verifying that the overall air lock leakage rate is ithin its limit: 1. At least once per 6 months # and 2. Prior to establishing PRIMARY CONTAIWlENT INTEGRITY when maintenance has been performed on the air lock that could affect the air lock sealing capability." c. At least once per 6 months by verifying that only one door in each air lock can be opened at a time. d. By verifying each airlock door inflatable seal system OPERABLE by: 1. Demonstrating each of the two inflatable seal pressure instrumentation channels per airlock door OPERABLE by performance of a: a) CHANNEL FUNCTIONAL TEST tt least once per 31 days, and b) CHANNEL CALIBRATIDN at least once per 18 months, with a low pressure setpoint of > 60 psig. 2. At least once per 7 days, verifying seal air flask pressure to be greater than or equal to 4& psig. l 90 3. At least once per 18 months, conducting a seal pneumatic system leak test and verifying that system pressure does not decay more than 2 psig from 90 psig within 48 hours. I The provisions of Specification 4.0.2 are not applicable. Exemption to Appendix J of 10 CFR 50. l GRAND GULF-UNIT 1 3/4 6-6 p. -,m-- --a ,f e- -,---=e m----- -..-.,e -,ur-- a.,,-, ,.--n-,w---.-,-

CONTA! WENT SYSTEMS SURVEILLANCE REQUIREMENTS l 4.6.2.3 Each drywell air lock shall be demonstrated OPERABLE: a. Within 8 hours after each closing, except when the air lock is being used for multiple entries, then at least once per 72 hours, by verifying seal leakage rate less than or equal to 2 scf per hour when the gap between the door semis is pressurized to P,, 11.5 psig. b. At least once per 6 months by conducting an overall air lock leakage test at P,11.5 psig and by veriping that the overall air lock leakageriteiswithinitslimit. c. At least once per 6 months by verifying that only one door in each . air lock can be opened at a time. d. By verifying each airlock door inflatable seal system OPERABLE by: 1. Demonstrating each of the'two inflatable seal pressure instrumentation channels per airloi:k door OPERABLE by performance of a: a) CHANNEL FUNCTIONAL TEST at least once per 31 days, and b) CHANNEL CALIBRATION at least once per 18 months, with a low pressure setpoint of > 60 psig. 2. At least once per 7 days verifying seal air flask pressure to be greater than or equal to # psig. I 90 3. At least once per 18 months, conducting a seal pneumatic systen leak test and verifying that systen pressure does not decay more than 2 psig from 90 psig within 48 hours.

  1. The provisions of Specification 4.0.2 are not applicable.

GRAPG GULF-UNIT 1 3N 6-16 ~-~~ ---e- -,e ,,,-..+,. m--- - - -,. ,,,_,-.a ,+,,,-..e.,- -,--e--. ,--,-,._,--a,-,re,-

4 CONTAINMENT ISSUES A. (MP&L P/L Item No. 15)

SUBJECT:

Drywell/ Containment Instrumentation Barometric Pressure Concerns, Technical Specification Tables 2.2,1-1, 3.3.2-2, 3.3.3-2, and 3.3.8-2 and Bases 2.2.1, 3/4.3.2, 3/4.3.3, and 3/4.3.8. DESCRIPTION Revisions to the subject Technical Specification tables and 0F CHANGE: bases are proposed to account for the effects of negative barometric pressure changes on drywell and containment pressure instrumentation. 1. The drywell and containment pressure instrument setpoints and allowable values in the subject tables should be revised to account for the effects of the worst case negative barometric pressure changes; applicable setpoints and allowable values should be reduced by 0.50 psi. (Pages 2-4, 3/4 3-15, 3/4 3-16, 3/4 3-17a, 3/4 3-28, and 3/4 3-99) 2. Applicable bases sections should be revised to address the effects of barometric pressure changes en the drywell/ containment pressure instrument setpoints and allowable values. (Pages B 2-8, B 3/4 3-1, B 3/4 3-2, and B 3/4 3-6) JUSTIFICATION: In the Grand Gulf design, both the drywell and containment pressure instrumentation provide trip signals that sre necessary to ensure the capability to prevent or mitigate the consequences of accidents that could result in potential offsite exposure. The drywell pressure instrumentation also provide trip signals to ensure the capability to achieve and maintain a safe shutdown condition. The drywell/ containment pressure instrumentation does not automatically compensate for changes in barometric pressure. Historical weather information for this locale indicates that the largest negative barometric deviation from standard pressure, that can reasonably be expected to be seen by the drywell and containment, is 0.50 psi. In order to ensure that the instrument trip setpoints (set during normal barometric pressure conditions) are not exceeded during worst case conditions, the high pressure trip setpoints should be reduced-t by 0.50 psi. The calibration procedures which are presently utilized require the setpoints to be reduced 0.50 psi from the technical specification values. However, this is an administrative control and not a technical specification requirement. The proposed change will ensure that the barometric pressure concern is properly addressed in the technical specifications. The proposed changes to the bases will provide additional information concerning the effect of barometric pressure changes on the drywell/ containment pressure instrumentation trip setpoints and allowable values. L46soi-

4. CONTAINMENT ISSUES (Continued) A. (MP&L P/L Item No. 15) The changes in drywell pressure instrumentation setpoints and allowable values are considered by MP&L to be temporary. An analysis is in progress to justify changing the drywell pressure analytical limit of 2.0 psid to 2.5 psid. This analysis should allow the drywell pressure setpoints and allowable value to be returned to their present values. SIGNIFICANT HAZARDS CONSIDERATION: The incorporation of the proposed changes into the technical specifications will ensure continuation of the practice of calibrating the drywell and containment pressure trip setpoints to account for variations in barometric pressure. The proposed changes to the Bases are considered administrative in that they add clarification to the existing discussions. MP&L considers the proposed setpoint and allowable value changes to be conservative in that the largest negative barometric pressure change based on historical weather information for this locale has been factored into the drywell/ containment pressure trip setpoints and allowable values. The proposed changes are not considered to: 1. Involve a significant increase in the probability or consequences of an accident previously evaluated; or 2. Create the possibility of a new or different kind of accident from any accident previously evaluated; or 3.- Involve a significant reduction in a margin of safety. Thus, the proposed changes have been evaluated and determined to involve no significant hazards as defined in 10 CFR 50.92. L46sd2 . :c

4 CONTAINMENT ISSUES (Continued) B.,(MP&L P/L Item No. 016)

SUBJECT:

Containment Pressure Setpoints and Allowable Values, Technical Specification Table 3.3.8-2. . DESCRIPTION A revision to Technical Specification Table 3.3.8-2 is proposed 0F CHANGE: to achieve consistency between the Grand Gulf Technical Speci-fications and the current containment high pressure trip setpoint data provided by General Electric. Table 3.3.8-2 should be revised to require the containment high pressure trip setpoint and allowable value not to exceed 7.84 psig and 8.34 psig, respectively. (Page 3/4 3-99) JUSTIFICATION: The present Containment Pressure-High trip setpoint of 9.0 psig is in actuality the analytical limit for containment spray initiation.- Upon discovery the NSSS vendor revised the applicable design data sheet *. This revision to the General Electric design specification' data lowered the containment high pressure trip setpoint and allowable value to less than or equal to 8.34 psig and less than or equal to 8.84 psig, respectively. These new values also must be decreased by 0.50 psi to allow for the effects of extreme negative barometric pressure variations. These changes are discussed in Containment Issue A, MP&L P/L Item No. 15. To ensure operation consistent with these values, the new trip setpoint has been incorporated into plant use by way of administrative controls. The proposed change would incorporate these new values into the technical specification as well. SIGNIFICANT HAZARDS CONSIDERATION: The proposed changes to the Technical Specifications implement correct values for the containment high pressure trip setpoint and. allowable value. These proposed changes are based on the analytical limit (9.0 psig) for containment spray actuation and the proper utilization of MP&L setpoint methodology (MP&L Response to NRC Question 31.60 - GGNS FSAR.) These proposed values also incorporate conservative considerations for adverse ambient barometric pressure fluctuations, as discussed in Section 4.A.. In that the proposed changes are consistent with safety analyses and are conservatively corrected for adverse barometric. pressure fluctuations, it has been determined that the changes do not: L* GE Technical Specification Data Sheet Number 22A3139AK, P.evision 7 Table 4.5.2-1 .L44com1 ~. -

v.;, 4, CONTAINMENT ISSUES (Continued) B. (MP&L P/L Item No. 016) (1) Involve a significant increase in the probability or consequences of an accident previously evaluated; or (2) Create the possibility of a new or different kind of accident from any accident previously evaluated; or (3) Involve a significant reduction in a margin of safety. Thus, the proposed changes have been evaluated and determined to involve no significant hazard, as defined in 10 CFR 50.92. L44c'dm2

4. CONTAINMENT ISSUES (Continued) C. (MP&L P/L Item No. 033)

SUBJECT:

Containment Spray Timer Setpoints, Technical Specification Table 3.3.8 and Bases 3/4.3.8. DESCRIPTION Revisions to Technical Specification 3.3.8 and Bases 3/4.3.8 0F CHANGE: are proposed to ensure that the technical specifications specify containment spray timer setpoints and allowable values that are consistent with the analyzed minimum and maximum containment spray initiation times. 1. Table 3.3.8-2 should be revised to require that both containment spray system timers have a trip setpoint of 10.85 1.0.10 minutes and an allowable value of 10.26 - 0.00, + 1.18 minutes. In addition, the System B timer should be footnoted to indicate that the System B timer actually consists of two timers (E12-K093B and E12-K116) and that the trip setpoint for E12-K116 is not to exceed 10.00 seconds of the total 10.85 1 0.10 minutes. (Page 3/4 3-99) 2. Bases 3/4.3.8 should be revised to refer to the analyzed minimum and maximum time delays between the initiation of the accident and containment spray initiation, which are 10 minutes and 13 minutes, respectively. (Page B 3/4 3-6) JUSTIFICATION: The containment spray system is a subsystem of the residual heat removal (RHR) system. Two of three RHR trains provide the containment spray function. As described in FSAR Section ~6.2.1.1.5.5, the safety analyses assume that containment spray initiates no sooner than 10 minutes and no later than 13 minutes after a loss of coolant accident (LOCA). These values constitute the analytical limits for the initiation of containment spray. The lower limit of 10 minutes is based on directing RHR pump flow, via the low pressure coolant injection (LPCl) function, to the reactor vessel for at least the first 10 minutes of the postulated accident. This limit is established to ensure an adequate post-LOCA core cooling capability, consistent with the associated safety analyses. After 10 minutes, the analyses permit the diversion of RHR pump flow to the containment spray function. The upper time limit of 13 minutes for initiation of containment spray is related to minimizing post-LOCA containment pressure. The initiation logic for the two spray trains is slightly different. Train B logic varies from Train A in that it has an additional timer to delay the initiation of that train for up to 90 seconds following the e,tpiration (tripping) of the initial 10 minute timer. This additional time delay is presently provided to prohibit simultaneous spray train ' initiation. H18sd1

i.i It. 4.. CONTAINMENT-ISSUES (Continued) C. '(MP&L P/L Item No. 033) 'It has been determined that the calculations necessary to establish the overall loop accuracy do not accurately reflect all parameters..With the present timer settings the possi-bility of exceeding the analytical limits for containment spray initiation exists. To ensure that this does not occur, calculations have been performed to determine new timer set- . points. These new setpoints are shown below: Trip Allowable Timers Setpoint Value System A 10.85 0.10 min. 10.26 to 11.44 min. System B 10.85 0.10 min. 10.26 to 11.44 min. These propose 1 setpoints and allowable values reflect the elimination of the 90 second time delay from. System B. The current safety analyses (FSAR Section 6.2.1.1.4.2) include consideration of the containment response to simultaneous spray train initiation. The results of this analysis demonstrate that. containment design requirements are met during this maximum depressurization transient, thus the 90 second time delay for System B initiation is unnecessary. The bases for the new setpoint and allowable values were determined by General Electric and reviewed and approved by MP&L. For the purpose of calculating the new values, an upper analytical limit of 11.70 minutes was used. (i.e.,13 minutes minus the maximum allowable containment spray isolation valve opening' time of 1.30 minutes). The new trip setpoint of 10.85 1.10 minutes is midway between the lower analytical limit of 10 minutes'and the 11.70 minute upper limit. Implementation of this trip setpoint and corresponding allowable values ensures that the containment spray system will l actuate without exceeding either'the upper or lower analytical limit. The proposed footnote for the System B timer will clarify that the new trip setpoint for-System B is the sum of the two timers in~that' system..In addition, the footnote will specify that the present'90-second delay is to'be set at a value not to exceed 10.00 seconds. The proposed addition to the bases will clarify that containment spray initiation is bounded by both an upper and lower analytical limit. H18sd2

4. - CONTAINMENT ISSUES (Continued)

C. (MP&L P/L Item No. 033) SIGNIFICANT HAZARDS CONSIDERATION: These changes have been proposed to render the technical specification and bases consistent with new containment spray timer trip setpoints, allowable values, and analytical limits as presented in FSAR Section 6.2.1.1.5.5. Implementation of these new values will ensure that containment spray will actuate only after the core has received at least 10 minutes of LPCI flow. The new values also ensure that the upper limit of 13 minutes, for containment spray actuation, will not be exceeded. MP&L considers the change in timer values necessary to correct an error that exists in the present Technical Specifications. The new timer values are consistent with purpose of the containment spray system and therefore are not considered to: (1)' Involve a significant increase in the probability or consequences of an accident previously evaluated; or (2) Create the possibility of a new or different kind of accident from any accident previously evaluated; or (3) Involve a significant reduction in a margin of safety. Thus the proposed changes have been evaluated and determined to involve no significant hazard, as defined in 10 CFR 50.92. H18sd3 l 1

TABLE 2e2.1-1 REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS a ALLOWABLE = g FUNCTIONAL UNIT TRIP SETPOINT VALUES l 1. Intemediate Range Monitor, Neutron Flux-High i 120/125 divisions 1 122/125 divisions i-of full scale of full scale 2. Average Power Range Monitor: E a. Neutron Flux-High, Setdown S 15% of RATED $ 20% of RATED Q THERMAL POWER THERMAL POWER M b. Flow Biased Simulated Themel Power-High

1) Flow Biased 5 0.66 W+485, with 1'0.66 W+515, with j

a maximum of a maximum of l

2) High Flow Clamped 5 111.0% of RATED 1 113.0% of RATED t

THERMAL POWER THERMAL. POWER c. Neutron Flux-High 5 1185 of RATED $ 120% of RATED THERMAL POWER THERMAL POWER d. Inoperative NA NA y 3. Reactor Vessel Steam Dome Pressure - High 5 1064.7 psig 1 1079.7 psig 4. Reactor Vessel Water Level - Low, Level 3 -> 11.4 inches above > 10.8 inches above l instrument zero* instrument zero* 5. Reactor Vessel Water Level-High, Level 8 < 53.5 inches above < 54.1 inches above f instrument zero* instrument zero" l 6. Main Steam Line Isolation Valve - Closure 1 6% closed i 7% closed 7. Main Steam Line Radiation - High 1 3.0 x full power $ 3.6 x full power gground t;agground 8. Drywell Pressure - High 1 73-psig 5 +c9& psig l 9. Scram Discharge Volume Water Level - High i 60% of full scale 1 635 of full scale

10. Turbine Stop Valve - Closure

> 40 psig** > 37 psig

11. Turbine Control Valve Fast Closure, Trip 011 Pressure - Low

> 44.3 psig** > 42 psig 12. Reactor Mode Switch Shutdown Position MA NA 13. Manual Scram NA NA See Bases Figure B 3/4 3-1.

    • Initial setpoint.

Final setpoint to be determined during startup test program. Any required change to this setpoint shall be submitted to the Commission within 90 days of test completion.

_TA8LE 3.3.2-2 y ISOLATION ACTUATION INSTRUMENTATION SETPOINTS 5 o ALLOWABLE E . TRIP FUNCTION TRIP SETPOINT VALUE 1. PRIMARY CONTAINMENT ISOLATION Q a. Reactor Vessel Water Level - p Low Low, Level 2 > -41.6 inches

  • 1 -43.8 inches b.

Reactor Vessel Water Level- > -41.6 inches * > -43.8 inches Low Low, level 2 (ECCS - ~ ~ Division 3) c. Reactor Vessel Water Level- > -150.3 inches * > -152.5 inches low Low Loe, level 1 (ECCS Division 1 and Division 2) f, g gyg w d. Drywell Pressure - High 5 -1r73 psig 1 -h9fF psig k /. 39 /4F w e. Drywell Pressure-High (ECCS - 14r89-psig 1-h94 psig 4 Division.1 and Division 2) m /M A W. f. Drywell Pressure-High (ECCS - 5 -h89-psig 1 -h9+- psig Division 3) g. Containment and Drywell Ventilation Exhaust Radiation - High High 5 2.0 nr/hr** 1 4.0 ar/hr** h. Manual Initiation NA NA 2. MAIN STEAM LINE ISOLATION a. Reactor Vessel Water Level - Low Low Low, Level 1 1 -150.3 inches * > -152.5 inches b. Main Steam Line Radiation - High 1 3.0 x full power i 3.6 x full power 4 background background c. Main Steam Line Pressure - Low > 849 psig > 837 psig d. Main Steam Line Flow - High 5 169 psid i 176.5 psid e: Condenser Vacuum - Low > ? inches Hg. Vacuum > 8.7 inches Hg. Vacuum f. Main Steam Line Tunnel Temperature - High 5 185'F** 1 191*F**

k TABLE 3.3.2-2 (C:ntinued) ,:= j-ISOLATION ACTUATION INSTRUMENTATION SETPOINTS o E ALLOWABLE TRIP FUNCTION TRIP SETPOINT, VALUE Z 2. MAIN STEAM LINE ISOLATION (Continued) g. Main Steam Line Tunnel a Temp. - High 5 101*F** 1 104*F** i h. Manual Initiation NA~ NA 3. SECONDARY CONTAINMENT ISOLATION 2 a. Reactor Vessel Water Level - Low Low, Level 2 > -41.6 inches' > -43.8 inches b. Drywell Pressure - High i n,sig i s,sig l l c. Fuel Handling Area Ventilation l { Exhaust Radition - High High 1 2.0 mR/hr** 1 4.0 mR/hr** I w d. Fuel Handling Area Pool Sweep g Exhaust Radiation - High High 1 18 mR/hr** $ 35 mR/hr** ~ e. Manual Initiation NA NA 4. REACTOR WATER CLEANUP SYSTEN ISOLATION a. A Flow - High < 79 gpa < 89** gpm 4 b. A Flow Timer 5 45 seconds 5 57 seconds c. Equipment. Area Temperature - High 1. RWCU Hx Room < 124*F < 130*F 2. RWCU. Pump Rooms 5174*F $ 180*F q i 3. RWCU Valve Nest Room .< 139'F < 145'F i 4. RWCU Demin. Rooms < 139'F I 145'F j 5. RWCU Rec. Tank Room i 139'F 7 145'F 6. RWCU Demin. Valve Room i 135'F 7 141*F \\ d. Equipment Area a Temp. - High 1. RWCU Hx Room < 65'F < 66'F 2. RWCU Pump Rooms 7 115'F 7 118'F j 3, RWCU Valve Nest Room 7 70*F 7 73*F i 4. RWCU Demin Rooms 7 70*F 7 73*F i 5. RWCU Rec. Tank Room 7 70*F 7 73*F 1 6. RWCU Demin. Valve Room 371*F 574'F 4

1 TABLE 3.3.2-2 (C ntinued) E 4 5 ISOLATION ACTUATION INSTRUMENTATION $ETPOINTS E TRIP FUNCTION ALLOWABLE E TRIP SETPOINT VALUE a 5. REACTOR CORE ISOLATION COOLING SYSTEN ISOLATION (Continued) i 5 1. Manual Initiation I H NA NA /.39 l.4% i m. Drywell Pressure-High (ECCS Division 1 14:09-psig 1-hS4 psig and Division 2) 4 6. -RHR SYSTEN ISOLATION 4 RHR Equipment Room Ambient Temperature a. High 5 169'F** 5 175*F** g RHR Equipment Room a Temperature - High 5 105'F** 1 108'F** b. Reactor Vessel Water Level - Low, Level 3 2 11.4 inches

  • 1 10.8 inches i.,

c. A 2f d. Reactor Vessel (RHR Cut-in Permissive) i Pressure - High 5 135 psig i 150 psig ) /.23 Drywell Pressure - High 5-1 psig 14 psig /. 43 e. f. Manual Initiation NA NA i l 4 = l See 8ases Figure 8 3/4 3-1. j Aa Initial setpoint. Final setpoint to be determined during startop test program. Any required change to j this setpoint shall be submitted to the Commission within 90 days of test completion.

1 TABLE 3.3.3-2 1 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRtmENTATION SETPOINTS i ALLOWA8LE-E TRIP FUNCTION TRIP SETPOINT VALUE E A. DIVISION 1 TRIP SYSTEM h 1. RHR-A (LPCI MODE) AND LPCS SYSTEM i i 4 Reactor Vessel Water Level - Low Low Low, Level 1 > -150.3 inches * > -152.5 inches. a. j w b. Drywell Pressure - High /.37 5-h69 psig /.W3 h94 psig l c. LPCI Pump A Start Time Delay Relay < 5 seconds 5 5.25 seconds d. Manual Initiation NA NA 2. AUTOMATIC DEPRESSURIZATION SYSTEM TRIP SYSTEM "A" Reactor vessel. Water Level - Low Low Low, Level 1 > -150.3 inches *- > -152.5 inches a. i b. Drywell Pressure - High /.37 5 -het psig AW54r94psig l i c. ADS Timer < 105 seconds < 117 seconds d. Reactor Vessel Water Level-Low, Level 3 5 11.4 inches

  • I 10.8 inches e.

LPCS Pump Discharge Pressure-High 145 psig, increasing 125-165 psig, increasing f. LPCI Pump A Discharge Pressure-High 125 psig, increasing 115-135 psig, increasing l { g. Manual Initiation MA NA sa 8. DIVISION 2 TRIP SYSTEM l h 1. RHR 8 AND C (LPCI MODE) i a. Reactor Vessel Water Level - Low Low Low, Level 1 > -150.3 inches * > -152.5 inches b. Drywell Pressure - High /Jy 3 4 89-psig /.9F3+c94 psig l l c. LPCI Pump 8 Start Time Delay Relay < 5 seconds 5 5.25 seconds d. Manual Initiation NA NA 2. AUTOMATIC DEPRESSURIZATION SYSTEM TRIP SYSTEM "B" a. Reactor vessel Water Level - Low Low Low, Level 1 > -150.3 inches * > -152.5 inches l 1 b. Drywell Pressure - High /J9 3 -h49 psig /.W3+c94psig l c. ADS Timer < 105 seconds < 117 seconds d. Reactor Vessel Water Level-Low, Level 3 i 11.4 inches

  • i 10.8 inches j

e. LPCI Pump 8 and C Discharge Pressure-High I25 psig, increasing 115 psig, increasing f. Manual Initiation NA NA C. DIVISION 3 TRIP SYSTEM 1. HPCS SYSTEN a. Reactor vessel Water Level - Low Low, Level 2 >-41.6 inches * >-43.8 inches

b. Drywell Pressure - High

/.593-hetpsig Aff 5-h94-psig l c. Reactor Vessel Water Level - High, Level 8 < 53.5 inches * < 55.7 inches d. Condensate Storage Tank Level - Low I O inches F_ -3 inches e. Suppression Pool Water Level - High < 5.9 inches < 6.5 inches i f. Manual Initiation NA NA 1 I i~

TABLE 3.3.8-2 PLANT SYSTEMS ACTUATION INSTRUMENTATION SETPOINTS ALLOWA8LE J g TRIP FUNCTION TRIP SETPOINT VALUE 1. CONTAlfttENT SPRAY SYSTEM 'O -f, l,* I 8 g g, N a. Drywell Pressure-High i W psIg 14HM-psIg j b. Containment Pressure-High 1 ? psig i 4,4 psig i c. Reactor Vessel Water Level-Low 784 8.54 i Low Low, Level 1 > - 150.3 inches > - 152.5 inches } d. Timers

1) System A to.95 t 010*# iG.3 ;.1 minutes 10 ^ 1.7, -0 minutes
2) System 8 10 B5 t 0.50 11.2

.2 minutes 11.0 .2, 1.5 minutes l 2. FEEDWATER SYSTEM / MAIN TUR8tNE TRIP SYSTEM u i ) a. Reactor Vessel Water Level-Hig'h, Level 8 5 53.5 inches

  • 1 55.7 inches T

e j "See Bases Figure 8 3/4 3-1. ) n Sirromt r.n Sysus B is Tua sum OF E12-ko95 6 Ps.o.s E12-k'11(.. E12-k114i ss Nor

r. sxceso i o. c o s ee.o u o s,

l d i I l l i 1 4 l l

[ LIMITING SAFETY SYSTEM SETTINGS BASES' REACTOR PROTECTION SYSTEM INSTRUMENTATION SETpnTNTS (Continued) 4. Reactor Vessel Water Level-Low The reactor vessel water level trip setcoint was chosen far enough below the normal operating level to avoid spurious trips but high enough above the fuel to assure that there is adequate protection for the fuel and pressure limits. 5. Reactor Vessel Water Level-Hich A reactor scram from high reactor water level, approximately two feet above normal operating level, is intended to offset the addition of reactivity effect associated with the introduction of a significant amount of relatively cold feedwater. An excess of feedwater entering the vessel would be detected by the level increase in a timely manner. This scram feature is only effective when the reactor mode switch is in the Run position because at THERMAL POWER levels below 107. to 157. of RATED THERMAL POWER, the approximate range of power level for changing to the Run position, the safety margins are more than adequate without a reactor scram. 6. Main Steam Line Isolation valve-Closure .The main steam line isolation valve closure trip was provided to limit the amount of fission product release for certain postulated events. The MSIV's are closed automatically from. measured parameters such as high steam flow, high steam line radiation, low reactor water level, high steam tunnel temperature and low steam line pressure. The MSIV's closure scram anticipates the pressure and flux transients which could follow MSIV closure and thereby protects reactor vessel pressure and fuel thermal / hydraulic Safety Limits. 7. Main Steam Line Radiation-Hioh l The main steam line radiation detectors are provided to detect a gross l failure of the fuel cladding. When the high radiation is detected, a trip is I initiated to reduce the continued failure of fuel cladding. At the same time the main steam line isolation valves are closed to limit the release of fission The trip setting is high enough above background radiation levels products. to prevent spurious trips yet low enough to promptly detect gross failures in the fuel cladding. 8. 'Drywell Pressure-Hich l High pressure in the drywell could indicate a break in the primary pressure The reactor is tripped in order to minimize the possibility boundary systems. The of fuel damage and reduce the amount of energy being added to the coolant. trip setting was selected as low as possible without causing spurious trips. NEG ATivs B AmeMornie. PMEss u ms Flue.TuATaows Amt Accouwyea rog e n Twg TR19 SsTroturs Area A uua wAss.s VAs.UE5 SPs curoco fan D n y wes.n. - PMES8uRE - HIGH, GRAND GULF-UNIT 1 8 2-8

i Negaf&e baromelnh pessurs Audadkas are aceo w kd for 4 /Je tap.retpoints and a//ocaaWe ya ker.spgeifted /or drywet/ pre.ssure. - /qh. " 3/4.3 INSTRUMENTATION BASES 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION The reactor protection system automatically initiates a reactor scram to: Preserve the integrity of the fuel cladding. a. b. Preserve the integrity of the reactor coolant system. Minimize the energy which must be adsorbed following a loss-of-coolant c. accident, and d. Prevent inadvartent criticality. This specification provides the limiting conditions for operation necessary to preserve the ability of the system to perform its intended function even during periods-when instrument channels may be out of service because of main-tenance. When necessary, one channel may be made inoperable for brief intervals to conduct required surveillance. The reactor protection system is made up of two independent trip systems. There are usually four channels.to monitor each parameter with two channels in each trip system. The outputs of the channels in a trip system are combined in a logic so that either channel will trip that trip system. The tripping of both trip systems will produce a reactor scram. The system meets the intent of IEEE-279 for nuclear power plant protection systems. The bases for the trip settings of the RPS are discussed in the bases for Specification 2.2.1. .The measurement of response time at the specified frequencies provides assurance that the protective functions associated with each channel are com-pleted within the time limit assumed in the accident analysis. No credit was taken for those channels with response times indicated as not applicable. Response time may be demonstrated by any series of sequential, overlapping or total channel test measurement, provided such tests demonstrate the total channel response time as defined. Sensor response time verification may be demonstrated by either (1) inplace, onsite or offsite test measurements, or (2) utilizing replacement sensors with certified response times. -3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION This specification ensures the effectiveness of the instrumentation used to mitigate the consequences of accidents by prescribing the OPERABILITY trip set-points and response times for isolation of the reactor systems. When necessary, ~ one channel may be inoperable for brief intervals to conduct required surveillance. o Some of the trip settings may have tolerances explicitly stated where both the high e and low values are critical and may have a substantial effect on safety. # The set-points of other instrumentation, where only the high or low end of the setting have a dire ~ct bearing on safety, are established at a level away from the normal-operating range to prevent inadvertent actuation of the systems involved. Except for the MSIVs, the safety analysis does not address individual sensor response times or the response times of the logic' systems to which the sensors are connected. For D.C. op'erated valves, A 3 second delay is assumed i before the valve starts to move. For A.C. operated valves, it is assumed that GRAND GULF-UNIT 1 B 3/4 3-1

Negat&e harome6,c pressore Schafios are accounted for th the inp setpoids ed 6//owable valuas.speciMd fo r- &ywe// pressure 4 L 7 INSTRUMENTATION BASES ISCLATION ACTUATION INSTRUMENTATION (continued) the A.C. power supply is lost and is restored by startup of the emergency diesel generators. In this event, a time of 13 seconds is assumed before the valve i starts to move. In addition to the pipe break, the failure of the D.C. operated valve is assumed; thus the signal delay (sensor response) is concurrent with the 13 second diesel startup. The safety analysis considers an allowable '1 inventory loss in each case which in turn determines the valve speed in conjunc-tion with the 13 second delay. It follows that checking the valve speeds and the 13 second time for emergency power establishment will establish the response time for the isolation functions. However, to enhance overall system relia-bility and to monitor instrument channel response time trends, the isolation actuation instrumentation response time shall be measured and recorded as a part of the ISOLATION SYSTEM RESPONSE TIME. Operation with a trip set less conservative than its Trip Setpoint but within its specified Allowable Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is equal to or greater than the drift allowance assumed for each trip in the safety analyses. 3/4.3.3 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION The emergency core cooling system actuation instrumentation is provided to initiate actions to mitigate the consequences of accidents that are beyond the ability of the operator to control. This specification provides the OPERA 8ILITY requirements, trip *setpoints and response times 'that williensure effectiveness of the systems to provide the design protection. #Although the instruments are listed by system, in some cases the same instrument may be used to send the actuation signal to more than one system at the same time. Operation with a trip set less conservative than its Trip Setpoint but within its specified Allowable Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is equal to or greater than the drift allowance assumed for each trip in the safety analyses. 3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION The anticipated transient without scram (ATWS) recirculation pump trip system provides a means of limiting the consequences of the unlikely occurrence i of a failure to scram during an anticipated transient. The response of the plant to this postulated event falls within the envelope of study events in General Electric Company Topical Report NEDO-10349, dated March 1971 and NEDO-24222, dated December 1979, and Section 15.8 Appendix 15A of the FSAR. The end-of-cycle racirculation pump trip (EOC-RPT) system is a part of the Reactor Protection System and is an essential safety supplement to the reactor trip. The purpose of the E0C-RPT is to recover the loss of thermal margin which occurs at the end of-cycle. The physical phenomenon involved is that the void reactivity feedback due to a pressurization transient can add positive reactivity to the reactor system at a faster rate than the control rods add negative scram reactivity. Each EOC-RPT system trips both recirculation pumps, reducing coolant _ flow in order to reduce the void collapse in the core during two of the most limiting pressurization events. The two events for which the EOC-RPT protective GRANO GULF-UNIT 1 8 3/4 3-2

INSTRUMENTATI'ON 8ASES l 3/4.3.7.11 RADI0 ACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION The radioactive liquid effluent monitoring instrumentation is provided to monitor and control, as applicable, the releases of radioactive materials in liquid effluents during actual or potential releases of liquid effluents. The alarm / trip setpoints for these instruments shall be calculated in accordance with the procedures in the ODCM to ensure that the alarm / trip will occur prior to exceeding the limits of 10 CFR Part 20. The OPERABILITY.and use of this instrumentation is consistent with the requirements of General Design Criteria 60, 63 and 64 of Appendix A to 10 CFR Part 50. 3/4.3.7.12 RADI0 ACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATIO The radioactive gaseous effluent monitoring instrumentation is provided to monitor and control, as applicable, the releases of radioactive materials in gaseous effluents during actual or potential releases of gaseous effluents. The alarm / trip setpoints for these instruments shall be calculated in accordance with the procedures in the 00CM to ensure that the alarm / trip will occur prior to exceeding the limits of 10 CFR Part 20. This instrumentation of potentially explosive gas mixtures in the waste gas holdup system. The OPERABILITY and use of this instrumentation is consistent with the requirements of General Design Criteria 60, 63 ad 64 of Appendix A to 10 CFR Part 50. 3/4.3.8 PLANT SYSTEMS ACTUATION INSTRUMENTATION The plant systems actuation instrumentation is provided to initiate action to mitigate the consequences of accidents that are beyond the ability of the operator to control. The LPCI mode of the RHR system is automatically initiated on a high drywell pressure signal and/or a low reactor water level, level 1, signal. The containment spray system will then actuate automatically d following high drywell and high containment pressure signals. # A 10-minute mWmum, l -> time delay exists between initiation of LPCI and containment spray actuation. A high reactor water level, level 8, signal will actuate the feedwater system / main turbine trip system. I G-minut e. maximm a% b y.sefpohde a n d a /t o w & t<. eakes speci A;ed for drywel and contammad pre.ssure hoyh. l i j GRAND GULF-UNIT 1 8 3/4 3-6 = - - -. -. -}}

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