ML053250215

Technical Specifications for Millstone Nuclear Power Station - Unit 3

ML053250215
Person / Time
Site:	Millstone
Issue date:	11/28/2005
From:	Office of Nuclear Reactor Regulation
To:	Dominion Nuclear Connecticut
Eads J, NRR/ADRO/DLR/RLRB, 415-1471
Shared Package
ML053220382	List: ML053220393 ML053220409 ML053220416 ML053220594 ML053250080 ML053250215
References
TAC MC1826 NUREG-1176
Download: ML053250215 (572)

Text

NUREG-1 176 CtUENSE AUTHORITY FILE COPY DO NOT REMOVE Technical Specifications Millstone Nuclear Power Station, Unit No. 3 Docket No. 50-423 Appendix "A" to License No. NPF-49 Issued by the U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation January 1986 UTO~~ IL CPDO NOT PFMOVF

NUREG-1 176 Technical Specifications Millstone Nuclear Power Station, Unit No. 3 Docket No. 50-423 Appendix "A" to License No. NPF-49 Issued by the U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation January 1986

INDEX INDEX DEFINITIONS SECTION PAGE 1.0 DEFINITIONS 1.1 ACTION . . . . . . . . . . . . . . . . . . . ... 1-1 1.2 ACTUATION LOGIC TEST . . . . . . . . . . . 1-1 1.3 ANALOG CHANNEL OPERATIONAL TEST . . . . . . . ... 1-1 1.4 AXIAL FLUX DIFFERENCE . . . . . . . . . . . 1-1 1.5 CHANNEL CALIBRATION . . . . . . . . . . . . ... 1-1 1.6 CHANNEL CHECK . . . . . . . . . . . . . . . 1-1 1.7 CONTAINMENT INTEGRITY . . . . . . . . . . . 1-2 1.8 CONTROLLED LEAKAGE . . . . . . . . . . . . 1-2 1.9 CORE ALTERATIONS . . . . . . . . . . . . . 1-2 1.10 DOSE EQUIVALENT 1-131 . . . . . . . . . . . 1-2 1.11 E-AVERAGE DISINTEGRATION ENERGY . . . . . . 1-3 I 1.12 DELETED 1.13 ENGINEERED SAFETY FEATURES RESPONSE TIME . . . . 1-3 1.14 DELETED 1.15 FREQUENCY NOTATION . . . . . . . . . . . . 1-3 1.16 IDENTIFIED LEAKAGE . . . . . . . . . . . . 1-3 1.17 MASTER RELAY TEST . . . . . . . . . . . . . 1-3 1.18 MEMBER(S) OF THE PUBLIC . . . . . . . . . . 1-4 1.19 OPERABLE - OPERABILITY . . . . . . . . . . 1-4 1.20 OPERATIONAL MODE - MODE . . . . . . . . . . . . . . 1-4 1.21 PHYSICS TESTS. 1-4 1.22 PRESSURE BOUNDARY LEAKAGE . . . . . .. . . 1-4 1.23 PURGE - PURGING. 1-4 1.24 QUADRANT POWER TILT RATIO . . . . .. . . . 1-5 1.25 DELETED 1.26 DELETED 1.27 RATED THERMAL POWER. 1-5 1.28 REACTOR TRIP SYSTEM RESPONSE TIME. . . . . 1-5 1.29 REPORTABLE EVENT . .. . . . . . .. . . . . . .1-5 1.30 SHUTDOWN MARGIN . . . . . . . . . . . . . . . . .1-5 1.31 SITE BOUNDARY . . . . . . . . . . . . . . . . . .1-5 MILLSTONE - UNIT 3 i Amendment No. Ff, F7, MP#,

0947 J??, 216

DEFINITIONS PAGE 1.32 SLAVE RELAY TEST................................... 1-6 1.33 SOURCE CHECK................................................. 1-6 1.34 STAGGERED TEST BASIS ......................................... 1-6 1.35 THERMAL POWER................................................ 1-6 1.36 TRIP ACTUATING DEVICE OPERATIONAL TEST....................... 1-6 1.37 UNIDENTIFIED LEAKAGE......................................... 1-6 1.38 UNRESTRICTED AREA............................... ..*.......... 1-6 1.39 VENTING...................................................... 1-7 1.40 SPENT FUEL POOL STORAGE PATTERNS.............................. 1-7 1.41 SPENT FUEL POOL STORAGE PATTERNS............................. 1-7 1.42 CORE OPERATING LIMITS REPORT (COLR).......................... 1-7 1.43 ALLOWED POWER LEVEL--APLND................................... 1-7 1.44 ALLOWED POWER LEVEL--APL. .............................. .... 1-7 I

TABLE 1.1 FREQUENCY NOTATION.................................... 1-8 TABLE 1.2 OPERATIONAL MODES....................................... 1-9 MILLSTONE - UNIT 3 ii Amendment No. af. fps fp. 7Xg e 7.100 0229 3fti 3 195

INDEX SAFFTY I IMITS ANn I IMITTN. SA"FFTY qYVTFM MTTNr4q SECTION PAGE 2.1 SAFETY LIMITS 2.1.1 REACTOR CORE . . . . . . . . . . . . . . . . . . . . . . . 2-1 2.1.2 REACTOR COOLANT SYSTEM PRESSURE . . . . . . . . . . . . . . 2-1 FIGURE 2.1-1 REACTOR CORE SAFETY LIMIT . . . . . . . . . . . . . 2-2 I FIGURE 2.1-2 DELETED . . . . . . . . . . . . . . . . . . . . . . 2-3 I 2.2 LIMITING SAFETY SYSTEM SETTINGS 2.2.1 REACTOR TRIP SYSTEM INSTRUMENTATION SETPOINTS . . . . . . . . . . 2-4 TABLE 2.2-1 REACTOR TRIP SYSTEM INSTRUMENTATION TRIP SETPOINTS . . . . 2-5 SECTION PAGE 2.1 SAFETY LIMITS 2.1.1 REACTOR CORE . . . . . . . . . . . . . . . . . . . . . . . . . B 2-1 2.1.2 REACTOR COOLANT SYSTEM PRESSURE . . . . . . . . . . . . . . . . B 2-2 2.2 LIMITING SAFETY SYSTEM SETTINGS 2.2.1 REACTOR TRIP SYSTEM INSTRUMENTATION SETPOINTS . . . . . . . . . B 2-3 MILLSTONE - UNIT 3 iii Amendment No. 217 0959

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE 3/4.0 APPLICABILITY ................................................... 3/40-1 3/4.1 REACTIVITY CONTROL SYSTEMS 3/4.1.1 BORATION CONTROL Shutdown Margin - MODES I AND2 ................................................... 3/4 1-1 Shutdown Margin - MODES 3,4, AND 5 LOOPS FILLED ........................ 3/4 1-3 FIGURE 3.1-1 DELETED .................................................... 3/4114 FIGURE 3.1-2 DELETED ................................................... 3/4 1-5 FIGURE3.1-3 DELETED ................................................... 3/4 1-6 FIGURE 3.1-4 DELETED ................................................... 3/4 1-7 Shutdown Margin - Cold Shutdown -

Loops Not Filled ................................................... 3/4 1-8 FIGURE 3.1-5 DELETED ................................................... 3/4 1-9 Moderator Temperature Coefficient ................................................... 3/4 1-10 Minimum Temperature for Criticality ................................................... 3/4 1-12 3/4.1.2 BORATION SYSTEMS DELETED ..... 3/4 1-13 DELETED ..... 3/4 1-14 DELETED ..... 3/4 1-15 DELETED ...... 3/4 1-16 DELETED ...... 3/4 1-17 DELETED ..... 3/41-18 3/4.1.3 MOVABLE CONTROL ASSEMBLIES Group Height ....... 3/4 1-20 TABLE 3. 1-1 ACCIDENT ANALYSES REQUIRING REEVALUATION IN THE EVENT OF AN INOPERABLE FULL-LENGrH ROD ...................... 3/4 1-22 Position Indication Systems - Operating ........................................ 3/4 1-23 MILLSTONE - UNIT 3 iv Amendment No. -0, 60,99, +9, >17, 218

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE DELETED ....................................... 3/4 1-24 Rod Drop Time ....................................... 3/4 1-25 Shutdown Rod Insertion Limit ....................................... 3/4 1-26 Control Rod Insertion Limits ....................................... 3/4 1-27 3/4.2 POWER DISTRIBUTION LIMITS 3/4.2.1 AXIAL FLUX DIFFERENCE ....................................... 3/4 2-1 3/4.2.2 HEAT FLUX HOT CHANNEL FACTOR - FQ(Z) ....................................... 3/4 2-5 3/4.2.3 RCS FLOW RATE AND NUCLEAR ENTHALPY RISE HOT CHANNEL FACTOR ............................................ 3/4 2-19 3/4.2.4 QUADRANT POWER TILT RATIO ....................... ..................... 3/4 2-24 3/4.2.5 DNB PARAMETERS ............................................ 3/4 2-27 TABLE 3.2-1 DELETED.................................................................................................... 3/4 2-28 I 3/41

.NSTRI

._ .. . ,\..

IMENTATTON

.. ^ ., ,. . A .

3/4.3.1 REACTOR TRIP SYSTEM INSTRUMENTATION .................................... 3/4 3-1 TABLE 3.3-1 REACTOR TRIP SYSTEM INSTRUMENTATION .................................... 3/4 3-2 TABLE 3.3-2 DELETED TABLE 4.3-1 REACTOR TRIP SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS .................................................. 3/43-10 3/4.3.2 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION ............. ..................................... 3/4 3-15 TABLE 3.3-3 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION ............. ..................................... 3/4 3-17 TABLE 3.3-4 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION TRIP SETPOINTS ................................................ 3/4 3-26 MILLSTONE - UNIT 3 v Amendment No. 60,6, 6 9, 9+, 2A, 244, 218

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE TABLE 3.3-5 DELETED TABLE 4.3-2 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS . . . 3/4 3-36 3/4.3.3 MONITORING INSTRUMENTATION Radiation Monitoring for Plant Operations . . . 3/4 3-42 TABLE 3.3-6 RADIATION MONITORING INSTRUMENTATION FOR PLANT OPERATIONS . . . . . . . . . . . . . 3/4 3-43 TABLE 4.3-3 RADIATION MONITORING INSTRUMENTATION FOR PLANT OPERATIONS SURVEILLANCE REQUIREMENTS . . . . . 3/4 3-45 TABLE 3.3-7 DELETED TABLE 4.3-4 DELETED TABLE 3.3-8 DELETED TABLE 4.3-5 DELETED Remote Shutdown Instrumentation . . . . . . . . . . . . 3/4 3-53 TABLE 3.3-9 REMOTE SHUTDOWN INSTRUMENTATION . . . . . . . . . . . . 3/4 3-54 TABLE 4.3-6 REMOTE SHUTDOWN MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS . . . . . . . . . . . . . . . 3/4 3-58 Accident Monitoring Instrumentation . . . . . . . . . . 3/4 3-59 TABLE 3.3-10 ACCIDENT MONITORING INSTRUMENTATION . . . . . . . . .. 3/4 3-60 TABLE 4.3-7 ACCIDENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS . . . . . . . . . . . . . . . . . . . . . 3/4 3-62 TABLE 3.3-11 DELETED I

TABLE 3.3-12 DELETED TABLE 4.3-8 DELETED MILLSTONE - UNIT 3 Vi Amendment No. up,77, 777,193 07566

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE TABLE 3.3-13 DELETED TABLE 4.3-9 DELETED 3/4.3.4 DELETED 3/4.3.5 SHUTDOWN MARGIN MONITOR . . . . . . . . . . . . . . . . . 3/4 3-82 3/4.4 REACTOR COOLANT SYSTEM 3/4.4.1 REACTOR COOLANT LOOPS AND COOLANT CIRCULATION Startup and Power Operation . . . . . . . . . . . . . . . 3/4 4-1 Hot Standby ................. . . . . . . 3/4 4-2 Hot Shutdown . . . . . . . .. . . . . . . . . . . . . . 3/4 4-3 Cold Shutdown - Loops Filled . . . . . . . . . . . . . . 3/4 4-5 Cold Shutdown - Loops Not Filled . . . . . . . . . . . . 3/4 4-6 Loop Stop Valves . . . . . . .. . . . . . . . . . . . . 3/4 4-7 I Isolated Loop Startup . . . . . . . . . . . . . . . . . . 3/4 4-8 3/4.4.2 SAFETY VALVES . . . . . . . . . . . . . . . . . . . . . . 3/4 4-9 DELETED . . . . . . . . . . . ... . . . . . . . . . . . . 3/4 4-10 3/4.4.3 PRESSURIZER Startup and Power Operation . . . . .

• 3/4 4-11 FIGURE 3.4-5 PRESSURIZER LEVEL CONTROL . . . . . .3/4 4-11a Hot Standby . . . . . . . . . . . . . . .3/4 4-I1b 3/4.4.4 RELIEF VALVES . . . . . . . . . . . .

• 3/4 4-12 3/4.4.5 STEAM GENERATORS . . . . . . . . . . . . . . . . . . . . .3/4 4-14 TABLE 4.4-1 MINIMUM NUMBER OF STEAM GENERATORS TO BE INSPECTED DURING INSERVICE INSPECTION . . . . . . . . . . . . . . . .3/4 4-19 TABLE 4.4-2 STEAM GENERATOR TUBE INSPECTION

• 3/4 4-20 3/4.4.6 REACTOR COOLANT SYSTEM LEAKAGE Leakage Detection Systems . . . . . . . . . . . . . . . . . 3/4 4-21 Operational Leakage.. .............. 3/4 4-22 TABLE 3.4-1 REACTOR COOLANT SYSTEM PRESSURE ISOLATION VALVES . . . 3/4 4-24 3/4.4.7 DELETED ........................ 3/4 4-25 TABLE 3.4-2 REACTOR COOLANT SYSTEM CHEMISTRY LIMITS . . . . . . . . 3/4 4-26 TABLE 4.4-3 REACTOR COOLANT SYSTEM CHEMISTRY LIMITS SURVEILLANCE REQUIREMENTS . . . . . . . . . . . . . . . . . . . . . . . 3/4 4-27 3/4.4.8 SPECIFIC ACTIVITY . . . . . . . . . . . . . . . . . . . . . 3/4 4-28 MILLSTONE - UNIT 3 vii Amendment No. Ipp, Ifr, IF?,

0960 I19. 707. 7G. -,-

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE FIGURE 3.4-1 DOSE EQUIVALENT I-131 REACTOR COOLANT SPECIFIC ACTIVITY LIMIT VERSUS PERCENT OF RATED THERMAL POWER WITH THE REACTOR COOLANT SPECIFIC ACTIVITY >1pCi/gram DOSE EQUIVALENT I-131 . . . . . . . . . . . . . . . . . 3/4 4-30 TABLE 4.4-4 REACTOR COOLANT SPECIFIC ACTIVITY SAMPLE AND ANALYSIS PROGRAM . . . . . . . . . . . . . . . . . . . . . . . . 3/4 4-31 3/4.4.9 PRESSURE/TEMPERATURE LIMITS . . . . . . . . . . . . . . 3/4 4-33 FIGURE 3.4-2 REACTOR COOLANT SYSTEM HEATUP LIMITATIONS -

APPLICABLE UP TO 10 EFPY . . . . . . . . . . . . . . . . 3/4 4-34 FIGURE 3.4-3 REACTOR COOLANT SYSTEM COOLDOWN LIMITATIONS -

APPLICABLE UP TO 10 EFPY . . . . . . . . . . . . . . . . 3/4 4-35 TABLE 4.4-5 REACTOR VESSEL MATERIAL SURVEILLANCE PROGRAM -

WITHDRAWAL SCHEDULE .... . . . . . . . . . . . . . . 3/4 4-36 Pressurizer ..... . . . . . . . . . . . . . . . . . 3/4 4-37 Overpressure Protection Systems . . . . . .. . . . . . 3/4 4-38 FIGURE 3.4-4a High Setpoint PORV Curve For the Cold Overpressure Protection System.. ........... 3/4 4-40 FIGURE 3.4-4b Low Setpoint PORV Curve For the Cold Overpressure Protection System . . . . . . . . . . . . . . . . . . . 3/4 4-41 I 3/4.4.10 DELETED . . . . . . . . . . . . . . . . . . . . . . . . 3/4 4-42 3/4.4.11 DELETED . . . . . . . . . . . . . . . . . . . . . . . . 3/4 4-43 3/4.5 EMERGENCY CORE COOLING SYSTEMS 3/4.5.1 ACCUMULATORS . . . . . . . . . . . . . . . . . . . . . . 3/4 5-1 3/4.5.2 ECCS SUBSYSTEMS - Tavg GREATER THAN OR EQUAL TO 350*F . . 3/4 5-3 3/4.5.3 ECCS SUBSYSTEMS - TaVg LESS THAN 350F . . . . . . . . . 3/4 5-7 3/4.5.4 REFUELING WATER STORAGE TANK . . . . . . . . . . . . . . 3/4 5-9 3/4.5.5 pH TRISODIUM PHOSPHATE STORAGE BASKETS . . . . . . . *

• 3/4 5-10 3/4.6 CONTAINMENT SYSTEMS 3/4.6.1 PRIMARY CONTAINMENT Containment Integrity . . . . . . . . . . . . . . . , . 3/4 6-1 Containment Leakage . . . . . . . . . . . . . . .. , . 3/4 6-2 Containment Air Locks . . . . . . . . . . . . . . . . . 3/4 6-5 Containment Pressure . . . . . . . . . . . . . . . . . . 3/4 6-7 MILLSTONE - UNIT 3 viii Amendment No. At, 97, b7, JJp, 0960 tff. 217 Al

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE FIGURE 3.4-1 DOSE EQUIVALENT 1-131 REACTOR COOLANT SPECIFIC ACTIVITY LIMIT VERSUS PERCENT OF RATED THERMAL POWER WITH THE REACTOR COOLANT SPECIFIC ACTIVITY >ljCi/gram DOSE EQUIVALENT I-131 . . . . . . . . . . 3/4 4-30 .

TABLE 4.4-4 REACTOR COOLANT SPECIFIC ACTIVITY SAMPLE AND ANALY SIS PROGRAM . . . . . . . . . . . . . . . . . . . . . . . 3/4 4-31 3/4.4.9 PRESSURE/TEMPERATURE LIMITS . . . . . . . . . . . . . 3/4 4-33 FIGURE 3.4-2 REACTOR COOLANT SYSTEM HEATUP LIMITATIONS -

APPLICABLE UP TO 10 EFPY . . . . . . . . . . . . . . . . . 3/4 4-34 FIGURE 3.4-3 REACTOR COOLANT SYSTEM COOLDOWN LIMITATIONS -

APPLICABLE UP TO 10 EFPY . . . . . . . . . . . . . . 3/4 4-35 TABLE 4.4-5 OELETED . . . . . . .. .. . . . . . . . . . . . 3/4 4-36 Pressurizer . . . . . . . . . . . . . . . . . . . . . 3/4 4-37 Overpressure Protection Systems . . . . . . . . . . . 3/4 4-38 FIGURE 3.4-4a NOMINAL MAXIMUM ALLOWABLE PORV SETPOINT FOR THE Co OLD OVERPRESSURE SYSTEM (FOUR LOOP OPERATION) . . . .. 3/4 4-40 FIGURE 3.4-4b NOMINAL MAXIMUM ALLOWABLE PORV SETPOINT FOR THE Cl OLD OVERPRESSURE SYSTEM (THREE LOOP OPERATION) . . . . . 3/4 4-41 3/4.4.10 DETETED . . . . . . . . . . . . .. . . . . . . . . 3/4 4-42 3/4.4.11 DELETED . . . . . . . . . . . . .. . . . . . .. . 3/4 4-43 3/4.5 EMERGENCY SORE COOLING SYSTEMS 3/4.5.1 ACCUMULATORS . . . . . . . . . . . . . . . . . . . . . 3/4 5-1 3/4.5.2 ECCS SUBSYSTEMS - Tavg GREATER THAN OR EQUAL TO 3500 F . 3/4 5-3 3/4.5.3 EC'S SUBSYSTEMS - Tavg LESS THAN 3500 F . . . .. . . . 3/4 5-7 3/4.5.4 REFUELING WATER STORAGE TANK . . . . . . . . . . . . . 3/4 5-9 3/4.5.5 pH TRISODIUM PHOSPHATE STORAGE BASKETS . . . . . . .

• 3/4 5-10 3/4.6 CONTAINMENT SYSTEMS 3/4.6.1 PRIMARY CONTAINMENT Containment Integrity . . . .. . . . . . . .. . . . 3/4 6-1 Containment Leakage . . . . .. . . . . . . . .. . . 3/4 6-2 Containment Air Locks . . . .. . . . . . . . .. . . 3/4 6-5 Containment Pressure . . . . . . . . . . . . . . . . . 3/4 6-7 MILLSTONE - UNIT 3 viii Amendment No. pi, 07. #is 1J9, 0870 79g, 214

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE Air Temperature ............................................... 3/4 6-9 Containment Structural Integrity ............................................... 3/4 6-10 Containment Ventilation System............................................... 3/4 6-11 3/4.6.2 DEPRESSURIZATION AND COOLING SYSTEMS Containment Quench Spray System .3/4 6-12 Recirculation Spray System .3/4 6-13 3/4.6.3 CONTAINMENT ISOLATION VALVES .3/46-15 314.6.4 DELETED 3/4.6.5 SUBATMOSPHERIC PRESSURE CONTROL SYSTEM Steam Jet Air Ejector ............. 3/4 6-18 3/4.6.6 SECONDARY CONTAINMENT Supplementaxy Leak Collection and Release System ................................ 3/4 6-19 Seconday Containent ............................................... 3/4 6-22 Secondary Containment Structural Integrity ............................................... 3/4 6-23 3/4.7 PLANT SYSTEMS 3/4.7.1 TURBINE CYCLE Safety Valves ............................................... 3/4 7-1 TABLE 3.7-1 MAXIMUM ALLOWABLE POWER RANGE NEUTRON FLUX HIGH SETPOINT WITH INOPERABLE STEAM LINE SAFETY VALVES ....... 3/4 7-2 TABLE 3.7-2 DELETED . ............... 3/4 7-2 MILLSTONE - UNIT 3 ix Amendment No. S9, 6}, 68, 9, 40, 444, 426,244, 224

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE TABLE 3.7-3 STEAM LINE SAFETY VALVES PER LOOP . . . . . . . . . 3/4 7-3 Auxiliary Feedwater System . . . . . . . . . . . . . 3/4 7-4 Demineralized Water Storage Tank . . . . . . . . . . 3/4 7-6 Specific Activity . . . . . . . . . . . . . . . . . 3/4 7-7 TABLE 4.7-1 SECONDARY COOLANT SYSTEM SPECIFIC ACTIVITY SAMPLE AND ANALYSIS PROGRAM . . . . . . . . . . . . . . . . 3/4 7-8 Main Steam Line Isolation Valves . . . . . . . . . . 3/4 7-9 Steam Generator Atmospheric Relief Bypass Lines . . 3/4 7-9a 3/4.7.2 DELETED . . . . . . . . . . . . . . . . . . . . . . 3/4 7-10 3/4.7.3 REACTOR PLANT COMPONENT COOLING WATER SYSTEM . . . . 3/4 7-11 3/4.7.4 SERVICE WATER SYSTEM . . . . . . . . . . . . . . . . 3/4 7-12 3/4.7.5 ULTIMATE HEAT SINK . . . . . . . . . . . . . . . . . 3/4 7-13 3/4.7.6 DELETED . . . . . . . .. . . . . . . . . . . . . . 3/4 7-14 I 3/4.7.7 CONTROL ROOM EMERGENCY VENTILATION SYSTEM . . . . . 3/4 7-15 3/4.7.8 CONTROL ROOM ENVELOPE PRESSURIZATION SYSTEM . . . . 3/4 7-18 3/4.7.9 AUXILIARY BUILDING FILTER SYSTEM . . . . . . . . . . 3/4 7-20 3/4.7.10 SNUBBERS. .. . .. 3/4 7-22 TABLE 4.7-2 SNUBBER VISUAL INSPECTION INTERVAL . . . . . . . . . 3/4 7-27 FIGURE 4.7-1 SAMPLE PLAN 2) FOR SNUBBER FUNCTIONAL TEST . . . . . 3/4 7-29 3/4.7.11 DELETED . . . . . . . . . . . . . . . . . . . . . . 3/4 7-30 3/4.7.12 DELETED Table 3.7-4 DELETED Table 3.7-5 DELETED 3/4.7.13 DELETED 3/4.7.14 AREA TEMPERATURE MONITORING . . . . . . . . . . . . 3/4 7-32 TABLE 3.7-6 AREA TEMPERATURE MONITORING . . . . . . . . . . . . 3/4 7-33 MILLSTONE - UNIT 3 X Amendment No. fl, gf, lpp, JHi, 214 0952

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE 314.8 ELECTRICAL POWER SYSTEMS 3/4.8.1 A.C. SOURCES Operating..................................................................................................3/4 8-1 DELETED ................................ 3/48-9 Shutdown ................................ 3/4 8-10 3/4.8.2 D.C. SOURCES Operating .3/4 8-11 TABLE 4.8-2a BATTERY SURVEILLANCE REQUIREMENTS .3/4 8-13 TABLE 4.8-2b BATTERY CHARGER CAPACITY .3/4 8-14 Shutdown 3. 3/48-15 3/4.8.3 ONSITE POWER DISTRIBUTION Operating.................................................................................................3/4 8-16 Shutdown .... 3/4 8-18 3/4.8.4 ELECTRICAL EQUIPMENT PROTECTIVE DEVICES DELETED................................................................................................3/4 8-19 DELETED .3/4 8-21 DELETED. 3/4 8-22 314.9 REFUELING OPERATIONS 3/4.9.1 BORON CONCENTRATION .3/4 9-1 3/4.9.2 INSTRUMENTATION..................................................................................3/4 9-2 3/4.9.3 DECAY TIME ................................... 3/4 9-3 3/4.9.4 CONTAINMENT BUILDING PENETRATIONS...................................... 3/4 9-4 3/4.9.5 DELETED ................................. 3/4 9-5 MILLSTONE - UNIT 3 xi Amendment No. 64, 424, ,49 225

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION EAE 3/4.9.6 DELETED ................................................. 3/4 9-6 3/4.9.7 3/4.9.8 DELETED .3/4 RESIDUAL HEAT REMOVAL AND COOLANT CIRCULATION 9-7 I High Water Level .... 3/4 9-8 Low Water Level .... 3/4 9-9 3/4.9.9 DELETED .... 3/4 9-10 3/4.9.10 WATER LEVEL - REACTOR VESSEL .... 3/49-11 3/4.9.11 WATER LEVEL - STORAGE POOL .... 3/49-12 3/4.9.12 DELETED .... 3/49-13 3/4.9.13 SPENTFUELPOOL-REACTIVITY .... 3/49-16 3/4.9.14 SPENT FUEL POOL - STORAGE PATTERN.......................................... 3/4 9-17 FIGURE 3.9-1 MINIMUM FUEL ASSEMBLY BURNUP VERSUS NOMINAL INITIAL ENRICHMENT FOR REGION I 4-OUT-OF-4 STORAGE CONFIGURATION............................................................3/4 9-18 FIGURE 3.9-2 REGION 1 3-0UT-OF4 STORAGE FUEL ASSEMBLY LOADING SCHEMATIC .3/4 9-19 FIGURE 3.9-3 MlqIMUM FUEL ASSEMBLY BURNUP VERSUS NOMINAL INITIAL ENRICHMENT FOR REGION 2 STORAGE CONFIGURATION. 3/4 9-20 FIGURE 3.9-4 MINIMUM FUEL ASSEMBLY BURNUP AND DECAY TIME VERSUS NOMINAL INITIAL ENRICHMENT FOR REGION 3 STORAGE CONFIGURATION. 3/4 9-21 3/4.10 SPECIAL TEST EXCEPTIONS 3/4.10.1 SHUTDOWN MARGIN ..................... 3/4 10-1 3/4.10.2 GROUP HEIGHT, INSERTION, AND POWER DISTRIBUTION LIMITS 3/410-2 3/4.10.3 PHYSICS TESTS ..................... 3/4 10-4 3/4.10.4 REACTOR COOLANT LOOPS ..................... 3/4 10-5 3/4.10.5 DELETED 3/11 DELETDh 3/4.11.1 DELETED 3/4.11.2 DELETED 3/4.11.3 DELETED MILLSTONE - UNIT 3 xii Amendment No. 39, 99, 4-,489, I ,I 21,249, 225

INDEX BASES SECTION PAGE 3/4.0 APPLICABILITY . . . . . . . . . B 3/4 0-1 3/4.1 REACTIVITY CONTROL SYSTEMS 3/4.1.1 BORATION CONTROL . . . . . . . . B 3/4 1-1 3/4.1.2 DELETED . . . . . . . . . B 3/4 1-2 3/4.1.3 MOVABLE CONTROL ASSEMBLIES B 3/4 1-3 3/4.2 POWER DISTRIBUTION LIMITS ................ B 3/4 2-1 3/4.2.1 AXIAL FLUX DIFFERENCE . . . . . . . . . . . . . . . . . B 3/4 2-1 3/4.2.2 and 3/4.2.3 HEAT FLUX HOT CHANNEL FACTOR AND RCS FLOW RATE AND NUCLEAR ENTHALPY RISE HOT CHANNEL FACTOR . . . B 3/4 2-3 3/4.2.4 QUADRANT POWER TILT RATIO . . . . . . . .. . .. . .. B 3/4 2-5 3/4.2.5 DNB PARAMETERS . . . . . . . . . . . . . . . . . . . . . B 3/4 2-5 3/4.3 INSTRUMENTATION 3/4.3.1 and 3/4.3.2 REACTOR TRIP SYSTEM INSTRUMENTATION AND ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMPNTATION B 3/4 3-1 3/4.3.3 MONITORING INSTRUMENTATION . . . . . . . . . . . . . . . B 3/4 3-3 3/4.3.4 TURBINE OVERSPEED PROTECTION . . . . . . . . . . . . . . B 3/4 3-6 3/4.3.5 SHUTDOWN MARGIN MONITOR ................ B 3/4 3-7 3/4.4 REACTOR COOLANT SYSTEM 3/4.4.1 REACTOR COOLANT LOOPS AND COOLANT CIRCULATION . . . . . B 3/4 4-1 3/4.4.2 SAFETY VALVES ..................... B 3/4 4-2 3/4.4.3 PRESSURIZER . . . . . . . . . . . . . . . . . . . . . . B 3/4 4-2 3/4.4.4 RELIEF VALVES ..................... B 3/4 4-2b 3/4.4.5 STEAM GENERATORS . . . . . . . . . . . . . . . . . . . . B 3/4 4-3 3/4.4.6 REACTOR COOLANT SYSTEM LEAKAGE . . . . . . . . . . . . . B 3/4 4-4 3/4.4.7 DELETED . . . . . . . . . . . . . . . . . . . . . . . . B 3/4 4-5 Il 3/4.4.8 SPECIFIC ACTIVITY ................... B 3/4 4-5 3/4.4.9 PRESSURE/TEMPERATURE LIMITS . . . . . . . . . . . . . . B 3/4 4-7 MILLSTONE - UNIT 3 xiii Amendment No. fg, is, 7fq, Aid, J97, 20.4

INDEX BASES SECTION PAGE TABLE B 3/4.4-1 REACTOR VESSEL FRACTURE TOUGHNESS PROPERTIES . . B 3/4 4-9 FIGURE B 3/4.4-1 FAST NEUTRON FLUENCE (E>lMeV) AS A FUNCTION OF FULL POWER SERVICE LIFE . .............. . B 3/4 4-10 3/4.4.10 DELETED . . . . . . . . . . . . . . . . . . . . . . . . . B 3/4 4-15 3/4.4.11 DELETED . . . . . . . . . . . . . . . . . . . . . . . . . B 3/4 4-15 3/4.5 EMERGENCY CORE COOLING SYSTEMS 3/4.5.1 ACCUMULATORS . . . . . . . . . . . . . 3/4 5-1 .B 3/4.5.2 and 3/4.5.3 ECCS SUBSYSTEMS . . . . . . 3/4 5-1 .B 3/4.5.4 REFUELING WATER STORAGE TANK . . . . . 3/4 5-2 .B 3/4.5.5 pH TRISODIUM PHOSPHATE STORAGE BASKETS B 3/4 5-3 3/4.6 CONTAINMENT SYSTEMS 3/4.6.1 PRIMARY CONTAINMENT . . . . . . . . . . B 3/4 6-1 3/4.6.2 DEPRESSURIZATION AND COOLING SYSTEMS B 3/4 6-2 3/4.6.3 CONTAINMENT ISOLATION VALVES .. . .. B 3/4 6-3 3/4.6.4 COMBUSTIBLE GAS CONTROL . . . . . . . . 3/4 6-3a .B 3/4.6.5 SUBATMOSPHERIC PRESSURE CONTROL SYSTEM 3/4 6-3d I .B 3/4.6.6 SECONDARY CONTAINMENT . . . . . . . . . B 3/4 6-4 3/4.7 PLANT SYSTEMS 3/4.7.1 TURBINE CYCLE . . . . . . . . . . . . . . . . 3/4 7-1 .

3/4.7.2 DELETED ................... 3/4 7-7 .

3/4.7.3 REACTOR PLANT COMPONENT COOLING WATER SYSTEM 3/4 7-7 .

3/4.7.4 SERVICE WATER SYSTEM . . . . . . . . . . . . 3/4 7-7 .

3/4.7.5 ULTIMATE HEAT SINK . . . . . . . . . . . . . 3/4 7-8 .

3/4.7.6 DELETED . . . . . . . . . . . . . . . . . . . B 3/4 7-10 .

3/4.7.7 CONTROL ROOM EMERGENCY VENTILATION SYSTEM . . B 3/4 7-10 .

3/4.7.8 CONTROL ROOM ENVELOPE PRESSURIZATION SYSTEM B 3/4 7-17 .

3/4.7.9 AUXILIARY BUILDING FILTER SYSTEM .. . . . . B 3/4 7-23 .

3/4.7. 10 SNUBBERS . . . . . . . . . . . . .. . . . . 3/4 7-23 .

MILLSTONE - UNIT 3 xiv Amendment No. %f,Fi, 7jt, 7y7, tf, 1025 Nf, 7J0. 216

INDEX BASES SE lQON EIfl1 3/4.7.11 DELETED .......................................B 3/4 7-25 3/4.7.12 DELETED 3/4.7.13 DELETED 3/4.7.14 AREA TEMPERATURE MONITORING ................... ................... B 3/4 7-25 3/4.8 ELECTRICAL OvER SYSTEmS 3/4.8.1, 3/4.8.2, and 3/4.8.3 A.C. SOURCES, D.C. SOURCES, AND ONSITE POWER DISTRIBUTION ............. ......................... B 3/4 8-1 3/4.8.4 DELETED .......................................B 3/4 8-3 3/4.9 REFUELING OPERArIONS 3/4.9.1 BORON CONCENTRATION..B 3/4 9-1 3/4.9.2 INSTRUMENTATION. .B 3/4 9-1 3/4.9.3 DECAY TIME..B 3/4 9-1 3/4.9.4 CONTAINMENT BUILDING PENETRATIONS..B 3/4 9-1 3/4.9.5 DELETED .B 3/4 9-1 3/4.9.6 DELETED .B 3/4 9-2 3/4.9.7 DELETED .B 3/4 9-2 3/4.9.8 RESIDUAL HEAT REMOVAL AND COOLANT CIRCULATION . B 3/4 9-2 3/4.9.9 DELETED .B 3/4 9-7 3/4.9.10 and 3/4.9.11 WATER LEVEL - REACTOR VESSEL AND STORAGE POOL .B 3/4 9-8 3/4.9.12 DELETED ...................................... B 3/4 9-8 3/4.9.13 SPENT FUEL POOL - REACTIVITY ................. ..................... B 3/4 9-8 3/4.9.14 SPENT FUEL POOL - STORAGE PAIRN ...................................... B 3/4 9-8 3/4.10 SPECIAL TEST EXCEPTIONS 3/4.10.1 SHU'TDOWN MARGIN. B 3/4 10-1 3/4.10.2 GROUP HEIGHT, INSERTION, AND POWER DISTRIBUTION LIMITS .B 3/4 1(-1 3/4.10.3 PHYSICS TESTS .B 3/4 10-1 3/4.10A REACTOR COOLANT LOOPS .B 3/4 10-1 3/4.10.5 DELETED. B 3/4 10-1 MILLSTONE - UNIT 3 xv Amendment No. 94, 84,40,407,4-49, 4-6,489, 492,, 2-7, 244, 249, 225

INDEX SECTION PAGE 3/4.11 DELETED 3/4.11.1 DELETED 3/4.11.2 DELETED 3/4.11.3 DELETED MILLSTONE - UNIT 3 xvil Amendment No. 188 0689

INDEX DESIGN FEATURES SECTION PAGE 5.1 SITE LOCATION .......................... . 5-1 I 5.2 DELETED I 5.3 REACTOR CORE 5.3.1 FUEL ASSEMBLIES . . . . . . . . . . . . . . . . . . . . . . . 5-5 5.3.2 CONTROL ROD ASSEMBLIES . . . . . . . . . . . . . . . . . . . 5-5 5.4 DELETED I 5.5 DELETED I 5.6 FUEL STORAGE 5.6.1 CRITICALITY . . . . . . . . . . . . . . . . . . . . . . . . . 5-6 5.6.2 DRAINAGE . . . . . . . . . . . . . . . . . . . . . . . . . . 5-6 5.6.3 CAPACITY . . . . . . . . . . . . . . . . . . . . . . . . . . 5-6 5.7 DELETED I MILLSTONE - UNIT 3 xvi i Amendment No. 212 0822 SEP 17 M

INDEX ADMINISTRATIVE CONTROLS SECTION PAGE 6.1 RESPONSIBILITY . . . . . . . . . . . . . . . . . . . . . . . . . 6-1 .

6.2 ORGANIZATION . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-1 6.2.1 OFFSITE AND ONSITE ORGANIZATIONS . . . . . . . . . . . . . . . . 6-1 6.2.2 FACILITY STAFF . . . . . . . . . . . . . . . . . . . . . . . . . 6-1 TABLE 6.2-1 MINIMUM SHIFT CREW COMPOSITION . . . . . . . . . . . . . 6-3 6.2.3 DELETED I 6.2.4 SHIFT TECHNICAL ADVISOR . . . . . . . . . . . . . . . . . . . 6-4 .

6.3 FACILITY STAFF QUALIFICATIONS 6-5 6.4 TRAINING . . . . 6-5 6.5 DELETED 6.6 DELETED 6.7 DELETED MILLSTONE - UNIT 3 xviii Amendment No. If, 7f, fy, py, 79i, jXg, 173 0637 1 . 7 -

INDEX ADMINISTRATIVE CONTROLS SECTION PAGE 6.8 PROCEDURES PROGRAMS ........................................................ 6-14 6.9 REPORTING REOUIREMENTS ........................................................ 6-17 6.9.1 ROUTINE REPORTS .6-17 Startup Report .6-17 Annual Reports .6-18 Annual Radiological Environmental Operating Report .6-19 Annual Radioactive Effluent Release Report .6-19 Core Operating Limits Report........................................................................6-19a 6.9.2 SPECIAL REPORTS .6-21 6.10 DELETED 6.11 RADIATION PROTECTION PROGRAM...................................................................... 6-21 6.12 HIGH RBAD1ATION AREA ......................................................... 6-21 6.13 RADIOLOGICAL EFLUENT MONITORING AND OFFSITE DOSE CALCULATION MANUAL (REMODCM) ......................................................... 6-24 6.14 RADIOACTIVE WASTE TREATMENT ............................... .......................... 6-24 6.15 RADIOACTIVE EFFLUENT CONTROLS PROGRAM................................................6-25 6.16 RADIOLOGICAL ENVIRONMENTAL MONITORING PROGRAM ......................... 6-26 6.17 REACTOR COOLANT PUMP FLYWHEEL INSPECTION PROGRAM .................... 6-26 6.18 TECHNICAL SPECIFICATIONS rTS) BASES CONTROL PROGRAM ..................... 6-26 6.19 COMPONENT CYCLIC OR TRANSIENT LIMIT .................................................... 6-27 MILLSTONE - UNIT 3 xix Amendment No. A6, 69, -6, *3, I-,

204, 22, 214, 223

SECTION 1.0 DEFINITIONS

1.0 DEFINITIONS The defined terms of this section appear in capitalized type and are applicable throughout these Technical Specifications.

ACTION 1.1 ACTION shall be that part of a Technical Specification which prescribes remedial measures required under designated conditions.

ACTUATION LOGIC TEST 1.2 An ACTUATION LOGIC TEST shall be the application of various simulated input combinations in conjunction with each possible interlock logic state and verification of the required logic output. The ACTUATION LOGIC TEST shall include a continuity check, as a minimum, of output devices.

ANALOG CHANNEL OPERATIONAL TEST 1.3 An ANALOG CHANNEL OPERATIONAL TEST shall be the injection of a simulated signal into the channel as close to the sensor as practicable to verify OPERABILITY of alarm, interlock and/or trip functions. The ANALOG CHANNEL OPERATIONAL TEST shall include adjustments, as necessary, of the alarm, inter-lock and/or Trip Setpoints such that the Setpoints are within the required range and accuracy.

AXIAL FLUX DIFFERENCE 1.4 AXIAL FLUX DIFFERENCE shall be the difference in normalized flux signals between the top and bottom halves of a two section excore neutron detector.

CHANNEL CALIBRATION 1.5 A CHANNEL CALIBRATION shall be the adjustment, as necessary, of the channel such that it responds within the required range and accuracy to known values of input. The CHANNEL CALIBRATION shall encompass the entire channel including the sensors and alarm, interlock and/or trip functions and may be performed by any series of sequential, overlapping, or total channel steps such that the entire channel is calibrated.

CHANNEL CHECK 1.6 A CHANNEL CHECK shall be the qualitative assessment of channel behavior-during operation by observation. This determination shall include, where possible, comparison of the channel indication and/or status with other indications and/or status derived from Independent instrument channels measuring the same parameter.

MILLSTONE - UNIT 3 1-1

DEFINITIONS CONTAINMENT INTEGRITY 1.7 CONTAINMENT INTEGRITY shall exist when:

a. All penetrations required to be closed during accident conditions are either:

1) Capable of being closed by an OPERABLE containment automatic isolation valve system*, or

2) Closed by manual valves, blind flanges, or deactivated automatic valves secured in their closed positions, except for valves that are opened under administrative control as permitted by Specification 3.6.3.

b. All equipment hatches are closed and sealed,

c. Each air lock is in compliance with the requirements of Specification 3.6.1.3,

d. The containment leakage rates are within the limits of the Containment Leakage Rate Testing Program, and

e. The sealing mechanism associated with each penetration (e.g., welds, bellows, or 0-rings) is OPERABLE.

CONTROLLED LEAKAGE 1.8 CONTROLLED LEAKAGE shall be that seal water flow supplied to the reactor coolant pump seals.

CORE ALTERATIONS 1.9 CORE ALTERATIONS shall be the movement of any fuel, sources, reactivity control components, or other components affecting reactivity within the reactor vessel with the vessel head removed and fuel in the vessel. Suspension of CORE ALTERATIONS shall not preclude completion of movement of a component to a safe position.

DOSE EQUIVALENT I-131 1.10 DOSE EQUIVALENT 1-131 shall be that concentration of I-131 (microCurie/gram) which alone would produce the same thyroid dose as the quantity and isotopic mixture of I-131, 1-132, I-133, I-134, and I-135 actually present. The thyroid dose conversion factors used for this calculation shall be those listed in NRC Regulatory Guide 1.109, Revision 1, "Calculation of Annual Doses to Man from Routine Releases of Reactor Effluents for the Purpose of Evaluating Compliance with 10 CFR Part 50, Appendix I."

• In MODE 4, the requirement for an OPERABLE containment isolation valve system is satisfied by use of the containment isolation actuation pushbuttons.

MILLSTONE - UNIT 3 1-2 Amendment No. 79, 7?7, IN, 216 0936

DEFINITIONS E - AVERAGE DISINTEGRATION ENERGY 1.11 E shall be the average (weighted in proportion to the concentration of each radionuclide in the sample) of the sum of the average beta and gamma energies per disintegration (MeV/d) for the radionuclides in the sample.

1.12 DELETED ENGINEERED SAFETY FEATURES RESPONSE TIME 1.13 The ENGINEERED SAFETY FEATURES (ESF) RESPONSE TIME shall be that time interval from when the monitored parameter exceeds its ESF Actuation Setpoint at the channel sensor until the ESF equipment is capable of performing its safety function (i.e., the valves travel to their required positions, pump discharge pressures reach their required values, etc.). Times shall include diesel generator starting and sequence loading delays where applicable. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured. In lieu of measurement, response time may be verified for selected components provided that the components and the methodology for verification have been previously reviewed and approved by the NRC.

1.14 DELETED FREQUENCY NOTATION 1.15 The FREQUENCY NOTATION specified for the performance of Surveillance Requirements shall correspond to the intervals defined in Table 1.1.

IDENTIFIED LEAKAGE 1.16 IDENTIFIED LEAKAGE shall be:

a. Leakage (except CONTROLLED LEAKAGE) into closed systems, such as pump seal or valve packing leaks that are captured and conducted to a sump or collecting tank, or

b. Leakage into the containment atmosphere from sources that are both specifically located and known either not to interfere with the operation of Leakage Detection Systems or not to be PRESSURE BOUNDARY LEAKAGE, or

c. Reactor Coolant System leakage through a steam generator to the Secondary Coolant System.

MASTER RELAY TEST

1. 17 A MASTER RELAY TEST shall be the energization of each master relay and verification of OPERABILITY of each relay. The MASTER RELAY TEST shall include continuity check of each associated slave relay.

MILLSTONE - UNIT 3 1-3 Amendment No. 84, ,4-26, 4,-,

-126, 220

DEFINITIONS MEMBER(S) OF THE PUBLIC 1.18 MEMBER(S) OF THE PUBLIC shall include all persons who are not occupa-tionally associated with the plant. This category does not include employees of the licensee, its contractors, or vendors. Also excluded from this category are persons who enter the site to service equipment or to make deliveries.

This category does include persons who use portions of the site for recre-ational, occupational, or other purposes not associated with the plant.

The term "REAL MEMBER OF THE PUBLIC" means an individual who is exposed to existing dose pathways at one particular location.

OPERABLE - OPERABILITY 1.19 A system, subsystem, train, component or device shall be OPERABLE or have OPERABILITY when it is capable of performing its specified function(s),

and when all necessary attendant instrumentation, controls, electrical power, cooling or seal water, lubrication or other auxiliary equipment that are required for the system, subsystem, train, component, or device to perform its function(s) are also capable of performing their related support function(s).

OPERATIONAL MODE - MODE 1.20 An OPERATIONAL MODE (i.e., MODE) shall correspond to any one inclusive combination of core reactivity condition, power level, and average reactor coolant temperature specified in Table 1.2.

PHYSICS TESTS 1.21 PHYSICS TESTS shall be those tests performed to measure the fundamental nuclear characteristics of the reactor core and related instrumentation:

(1) described in Chapter 14.0 of the FSAR, (2) authorized under the provisions of 10 CFR 50.59, or (3) otherwise approved by the Commission.

PRESSURE BOUNDARY LEAKAGE 1.22 PRESSURE BOUNDARY LEAKAGE shall be leakage (except steam generator tube leakage) through a nonisolable fault in a Reactor Coolant System component body, pipe wall, or vessel wall.

PURGE - PURGING 1.23 PURGE or PURGING shall be any controlled process of discharging air or gas from a confinement to maintain temperature, pressure, humidity, concentration or other operating condition, in such a manner that replacement air or gas is required to purify the confinement.

MILLSTONE - UNIT 3 1-4

DEFINITIONS QUADRANT POWER TILT RATIO 1.24 QUADRANT POWER TILT RATIO shall be the ratio of the maximum upper excore detector calibrated output to the average of the upper excore detector cali-brated outputs, or the ratio of the maximum lower excore detector calibrated output to the average of the lower excore detector calibrated outputs, whichever Is greater. With one excore detector inoperable, the remaining three detectors shall be used for computing the average.

RATED THERMAL POWER 1.27 RATED THERMAL POWER shall be a total reactor core heat transfer rate to the reactor coolant of 3411 MWt.

REACTOR TRIP SYSTEM RESPONSE TIME 1.28 The REACTOR TRIP SYSTEM RESPONSE TIME shall be the time interval from when the monitored parameter exceeds its Trip Setpoint at the channel sensor until loss of stationary gripper coil voltage. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured. In lieu of measurement, response time may be verified for selected components provided that the components and the methodology for verification have been previously reviewed and approved by the NRC.

REPORTABLE EVENT 1.29 A REPORTABLE EVENT shall be any of those conditions specified in Section 50.73 of 10 CFR Part 50.

SHUTDOWN MARGIN 1.30 SHUTDOWN MARGIN shall be the instantaneous amount of reactivity by which the reactor is subcritical or would be subcritical from its present condition assuming all full-length rod cluster assemblies (shutdown and control) are fully inserted except for the single rod cluster assembly of highest reactivity worth which is assumed to be fully withdrawn.

MILLSTONE - UNIT 3 1-5 Amendment No. fp, JP7,188 0749

DEFINITIONS SITE BOUNDARY 1.31 The SITE BOUNDARY shall be that line beyond which the land is neither owned, nor leased, nor otherwise controlled by the licensee.

SLAVE RELAY TEST 1.32 A SLAVE RELAY TEST shall be the energization of each slave relay and verification of OPERABILITY of each relay. The SLAVE RELAY TEST shall include a continuity check, as a minimum, of associated testable actuation devices.

SOURCE CHECK 1.33 A SOURCE CHECK shall be the qualitative assessment of channel response when the channel sensor is exposed to radiation.

STAGGERED TEST BASIS 1.34 A STAGGERED TEST BASIS shall consist of:

a. A test schedule for n systems, subsystems, trains, or other designated components obtained by dividing the specified test interval into n equal subintervals, and

b. The testing of one system, subsystem, train, or other designated component at the beginning of each subinterval.

THERMAL POWER 1.35 THERMAL POWER shall be the total reactor core heat transfer rate to the reactor coolant.

TRIP ACTUATING DEVICE OPERATIONAL TEST 1.36 A TRIP ACTUATING DEVICE OPERATIONAL TEST shall consist of operating the Trip Actuating Device and verifying OPERABILITY of alarm, interlock and/or trip functions. The TRIP ACTUATING DEVICE OPERATIONAL TEST shall include adjustment, as necessary, of the Trip Actuating Device such that it actuates at the required Setpoint within the required accuracy.

UNIDENTIFIED LEAKAGE 1.37 UNIDENTIFIED LEAKAGE shall be all leakage which is not IDENTIFIED LEAKAGE or CONTROLLED LEAKAGE.

UNRESTRICTED AREA 1.38 An UNRESTRICTED AREA shall be any area at or beyond the SITE BOUNDARY to which access is not controlled by the licensee for purposes of protection of individuals from exposure to radiation and radioactive materials, or any area within the SITE BOUNDARY used for residential quarters or for industrial, commercial, institutional, and/or recreational purposes.

MILLSTONE - UNIT 3 1-6

DEFINITIONS VENTING 1.39 VENTING shall be the controlled process of discharging air or gas from a confinement to maintain temperature, pressure, humidity, concentration, or other operating condition, in such a manner that replacement air or gas is not provided or required during VENTING. Vent, used in system names, does not imply a VENTING process.

SPENT FUEL POOL STORAGE PATTERNS:

STORAGE PATTERN 1.40 STORAGE PATTERN refers to the blocked location in a Region 1 fuel storage rack and all adjacent and diagonal Region 1 (or Region 2) cell locations surrounding the blocked location. The blocked location is for criticality control.

3-OUT-OF-4 and 4-OUT-OF-4 1.41 Region 1 spent fuel racks can store fuel in either of 2 ways:

(a) Areas of the Region 1 spent fuel racks with fuel allowed in every storage location are referred to as the 4-OUT-OF-4 Region 1 storage area.

(b) Areas of the Region 1 spent fuel racks which contain a cell blocking device in every 4th location for criticality control, are referred to as the 3-OUT-OF-4 Region 1 storage area. A STORAGE PATTERN is a subset of the 3-OUT-OF-4 Region I storage area.

CORE OPERATING LIMITS REPORT (COLR) 1.42 The CORE OPERATING LIMITS REPORT (COLR) is the unit-specific document that provides core operating limits for the current operating reload cycle.

These cycle-specific core operating limits shall be determined for each reload cycle in accordance with Specification 6.9.1.6. Unit Operation within these operating limits is addressed in individual specifications.

ALLOWED POWER LEVEL 1.43 API[ is the minimum allowable nuclear design power level for base load operation and is specified in the COLR.

1.44 APLBL is the maximum allowable power level when transitioning into base load operation.

MILLSTONE - UNIT 3 1-7 Amendment No. p pp. F. fp, 7 FP89 cm 8

TABLE 1.1 FREQUENCY NOTATION NOTATION FREQUENCY S At least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />.

D At least once per 24 hours1 days <br />0.143 weeks <br />0.0329 months <br />.

w At least once per 7 days.

M At least once per 31 days.

Q At least once per 92 days.

SA At least once per 184 days.

R At least once per 18 months.

S/U Prior to each reactor startup.

N.A. Not applicable.

P Completed prior to each release.

MILLSTONE - UNIT 3 l-8 f, Leo

'I ,) id His dI

- - a' -/11

TABLE 1.2 OPERATIONAL MODES REACTIVITY  % RATED AVERAGE COOLANT MODE CONDITION, Keff THERMAL POWER* TEMPERATURE

1. POWER OPERATION > 0.99 > 5% > 350 0F

2. STARTUP > 0.99 < 5% > 3500F

3. HOT STANDBY < 0.99 0 > 3500F

4. HOT SHUTDOWN < 0.99 350 0 F > Taa 00

> 200OF avg

5. COLD SHUTDOWN < 0.99 < 2000F 0

6. REFUELING** < 0.95 < 140OF

• Excluding decay heat.

• • Fuel in the reactor vessel with the vessel head closure bolts less than fully tensioned or with the head removed.

MILLSTONE - UNIT 3 1-9

SECTION 2.0 SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS

2.0 SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS 2.1 SAFETY LIMITS REACTOR CORE 2.1.1 The combination of THERMAL POWER, pressurizer pressure, and the highest operating loop coolant temperature (Teav) shall not exceed the limits shown in Figure 2.1-1. I APPLICABILITY: MODES 1 and 2.

ACTION:

Whenever the point defined by the combination of the highest operating loop average temperature and THERMAL POWER has exceeded the appropriate pressurizer pressure line, be in HOT STANDBY within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

REACTOR COOLANT SYSTEM PRESSURE 2.1.2 The Reactor Coolant System pressure shall not exceed 2750 psia.

APPLICABILITY: MODES 1, 2, 3, 4, and 5.

ACTION:

MODES 1 and 2:

Whenever the Reactor Coolant System pressure has exceeded 2750 psia be in HOT STANDBY with the Reactor Coolant System pressure within its limit within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

MODES 3, 4 and 5:

Whenever the Reactor Coolant System pressure has exceeded 2750 psia, reduce the Reactor Coolant System pressure to within its limit within 5 minutes.

MILLSTONE - UNIT 3 2-1 UAnendment No. J77,217 0962

680 660 LL 640 16 LJ=

620 6S0 580 560 0 0.2 0.4 0.6 0.8 LO 1.2 FRACTION OF RATED THERMAL POWER FIGURE 2.1-1 REACTOR CORE SAFETY LIMIT I MILLSTONE - UNIT 3 2-2 Amendment No. pp,217 0962

This page intentionally left blank.

MILLSTONE - UNIT 3 2-3 0962 Amendment No. J0 o217

SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS 2.2 LIMITING SAFETY SYSTEM SETTINGS REACTOR TRIP SYSTEM INSTRUMENTATION SETpOINTS Z.2 I The Reactor Trip System Instrumentation and Interlock Setpoints shall be set consistent with the Nominal Trip Setpoint values shown in Table 2.2-1. I APPLICABILIY: As shown for each channel in Table 3.3-1.

ACTION:

a. With a Reactor Trip System Instrumentation Channel or Interlock Channel Nominal Trip Setpoint inconsistent with the value shown in the Nominal Trip Setpoint column of Table 2.2-1, adjust the Setpoint consistent with the Nominal Trip Setpoint value.

b. With a Reactor Trip System Instrumentation Channel or Interlock Channel found to be inoperable, declare the channel inoperable and apply the applicable ACTION statement requirement of Specification 3.3.1 until the channel is restored to OPERABLE status.

MILLSTONE - UNIT 3 2-4 Amendment No. 159

.0550 MA- 2 G 1328

TABLL 2.2-1 o=

(a- REACTOR TRIP SYSTEM-INSTRUMENTATION TRIP SETPOINTS

-4 0 NOMINAL mn FUNCTIONAL UNIT TRIP SETPOINT ALLOWABLE VALUE

-I

1. Manual Reactor Trip N.A. N.A.

w4 2. Power Range, Neutron Flux

a. High Setpoint 109% of RTP** < 109.6% of RTP** I

b. Low Setpoint 25% of RTP** < 25.6% of RTP**

3. Power Range, Neutron Flux, 5% of RTP** with < 5.6% of RTP** with High Positive Rate a time constant a time constant

> 2 seconds > 2 seconds

4. Deleted

5. Intermediate Range, 25% of RTP** < 27.4% of RTP**

Neutron Flux en

6. Source Range, Neutron Flux 1 X 10+5cps < 1.06 x 10+5 cps 3 7. Overtemperature AT See Note 1 See Note 2

a. I M

• • RTP - RATED THERMAL POWER zC+

-p.

TABLE 2 (Continued)

REACTOR TRIP SYSTEM INSTRUMENTATION TRIP SETPOINTS o =

W r, I-

-4 NOMINAL U¶1 FUNCTIONAL UNIT TRIP SETPOINT ALLOWABLE VALUE I

8. Overpower AT See Note 3 See Note 4 I P-4 (hi

9. Pressurizer Pressure-Low 1900 psia > 1897.6 psia

10. Pressurizer Pressure-High 2385 psia < 2387.4 psia

11. Pressurizer Water Level-High 89% of instrument < 89.3% of instrument span span

12. Reactor Coolant Flow-Low 90% of loop > 89.8% of loop design flow* design flow*

13. Steam Generator Water 18.1% of narrow > 17.8% of narrow Level Low-Low range instrument range instrument span span 0

14. General Warning Alarm N.A. N.A.

15. Low Shaft Speed - Reactor 92.4% of rated > 92.2% of rated Coolant Pumps speed speed UP 3

M 2

=1

• Minimum Measured Flow Per Loop X 1/4 of the RCS Flow Rate Limit as listed in Section 3.2.3.1.a I

"q

-4%

_U

LBLE 2.2-1 (Continued)

REACTOR TRIP SYSTEEM INSTRUMENTATION TRIP SETPOI]

NOMINAL r FUNCTIONAL UNIT TRIP SETPOINT ALLOWABLE VALUE 2 16. Turbine Trip

a. Low Fluid Oil Pressure 500 psig 2 450 psig

b. Turbine Stop Valve 1% open > 1% open Closure

17. Safety Injection Input N.A. N.A.

from ESF

18. Reactor Trip System Interlocks

a. Intermediate Range lx 10.10 amp Ž9.0 x 1011 amp Neutron Flux, P-6

b. Low Power Reactor Trips Block, P-7

1) Power Range Neutron Flux, 11% of RTP** < 11.6% of RTP**

P-10 input (Note 5)

I

2) Turbine Impulse Chamber Pressure, 10% RTP** Turbine

• 10.6% RTP** Turbine P-13 input I Impulse Pressure Impulse Pressure Equivalent Equivalent

c. Power Range Neutron 37.5% of RTP**

• 38.1% of RTP**

Flux, P-8

• • RTP = RATED THERMAL POWER PO ra.

r.3 0o

83 TABLE 2.2-1 (Continued)

WF I. REACTOR TRIP SYSTEM INSTRUMENTATION TRIP SETPOINTS 0-I i

Pi NOMINAL FUNCTIONAL UNIT TRIP SEIPOINT ALLOWABLE VALUE

d. Power Range Neutron 51% of RTP** < 51.6% of RTP**

Flux, P-9 To

e. Power Range Neutron 9% of RTP** > 8.4% of RTP**

Flux, P-10 (Note 6)

19. Reactor Trip Breakers N.A. N.A.

20. Automatic Trip and Interlock N.A. N.A.

Logic

21. DELETED I a.

0

4 z

rt, I-"a

• • RTP - RATED THERMAL POWER

-i

TABLE 2.2-1 (Continued!

TABLE NOTATIONS r NOTE 1:OVERTEMPERATURE AT (1rs o( e I S K K (I_) +

4 s) (T r) + K_ I(

Z l¶s I-K 2 T (T ') K 3(P.. P') fl.(Al) i Where: AT is measured Reactor Coolant System AT, 'F; ATO is loop specific indicated AT at RATED THERMAL POWER, 'F; (1 +TIS)

(I + G2 s) is the function generated by the lead-lag compensator on measured AT;

• T1 and T2 are the time constants utilized in the lead-lag compensator for AT, Tr 2 [*] sec, r2 * [*] sec; K1 *S[*]

K2 2 [*1/OF; (1 + c4s) is the function generated by the lead-lag compensator for Tavg; (17¶5 S)

T4 and x5 are the time constants utilized in the lead-lag compensator for Tavg, T4 2 sec. T5[* sec;[l T is measured Reactor Coolant System average temperature, 'F; T' is loop specific indicated Tavg at RATED THERMAL POWER, * [*1]F; K3 2 [*]/psi o P is measured pressurizer pressure, psia; P' is nominal pressurizer pressure, > [*] psia; s is the Laplace transform operator, sec-;

(The values denoted with [*] are specified in the COLR.)

co

TABLE 2.2-1 (Continued)

TABLE NO2TATIONS NOTE 1: (Continued) and f1 (Al) is a function of the indicated difference between top and bottom detectors of the power range neutron ion chambers; with nominal gains to be selected based on measured instrument response during plant startup tests calibrations such that:

(1) For qt - qb between [*]% and [*]%, fl, (AI) A [*], where qt and qb are percent RATED THERMAL POWER in the upper and lower halves of the core, respectively, and qt + qb is the total THERMAL POWER in percent RATED THERMAL POWER; (2) For each percent that the magnitude of qt - qb exceeds [*]%, the AT Trip Setpoint shall be automatically reduced by > [*]% of its value at RATED THERMAL POWER.

(3) For each percent that the magnitude of qt - qb exceeds [*]%, the AT Trip Setpoint shall be automatically reduced by > [*]% of its value at RATED THERMAL POWER.

NOTE 2: The maximum channel as left trip setpoint shall not exceed its computed trip setpoint by more than the following:

> (1) 0.4% AT span for the AT channel (2) 0.4% AT span for the Tavg channel (3) 0.4% AT span for the pressurizer pressure channel C (4) 0.8% AT span for the f(Al) channel

• (The values denoted with [*] are specified in the COLR.)

0z

TABLE 2.2-1 (Continnedl 7TABLE NOTATIONS o NOTE 3: OVERPOWER AT AT) I K K(7 T-K)(TrTs)

(TT? (1 +r 2 s) 4 -5(X +T 7s)T K 6 (T-Where: AT is measured Reactor Coolant System AT, 0F; ATo is loop specific indicated AT at RATED THERMAL POWER, OF; (1 +T'S)

(1 + T2 5) is the function generated by the lead-lag compensator on measured AT; T, and T2 are the time constants utilized in the lead-lag compensator for AT, t1 Ž [I] sec, T2 5 [*e] 5c; K45 1*];I K5 >[*]¶/F for increasing Tavg and Ks < [*] for decreasing Tavg; (T7y)

( + T S) is the function generated by the rate-lag compensator for Tavg; a 'T7 is the time constant utilized in the rate-lag compensator for Tavg, T7 2 [*] sec; 0.

i T is measured average Reactor Coolant System temperature, IF; z T" is loop specific indicated Tavg at RATED THERMAL POWER, 5 [*]OF; K6 2 [*]/OF when T > T" and K6 < [*]/F when T

• T";

s isthe Laplace transform operator, sec, 1; (The values denoted with 1*] are specified in the COLR.)

rN 0o

IABLL2 Lontied TABLE NOTATIONS (Continued)

-I NOTE 4: The maximum channel as left trip setpoint shall not exceed its computed trip setpoint by more than I 0.4% AT span for the AT channel and 0.4% AT span for the Tavg channel. I NOTE 5: Setpoint is for increasing power.

NOTE 6: Setpoint is for decreasing power.

=0 0.

'a

• p4

=

%0

BASES FOR SECTION 2.0 SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS

NOTE The BASES contained in succeeding pages summarize the reasons for the Specifications in Section 2.0, but in accordance with 10 CFR 50.36 are not part of these Technical Specifications.

2.1 SAFETY LIMITS BASFS 2.1.1 REACTOR CORE The restrictions of this Safety Limit prevent overheating of the fuel and possible cladding perforation which would result in the release of fission products to the reactor coolant. Overheating of the fuel cladding is prevented by restricting fuel operation to within the nucleate boiling regime where the heat transfer coefficient is large and the cladding surface temperature is slightly above the coolant saturation temperature.

Operation above the upper boundary of the nucleate boiling regime could result in excessive cladding temperatures because of the onset of departure from nucleate boiling (DNB) and the resultant sharp reduction in heat transfer coefficient. DNB is not a directly measurable parameter during operation and therefore THERMAL POWER and reactor coolant temperature and pressure have been related to DNB. This relation has been developed to predict the DNB flux and the location of DNB for axially uniform and nonuniform heat flux distributions.

The local DNB heat flux ratio (DNBR) is defined as the ratio of the heat flux that would cause DNB at a particular core location to the local heat flux and is indicative of the margin to DNB.

The DNB design basis is as follows: uncertainties in the WRB-1 or WRB-2 correlations, plant operating parameters, nuclear and thermal parameters, fuel fabrication parameters, and computer codes are considered statistically such that there is at least a 95 percent probability with 95 percent confidence level that DNBR will not occur on the most limiting fuel rod during Condition I and 1I events. This establishes a design DNBR value which must be met in plant safety analyses using values of input parameters without uncertainties. In addition, margin has been maintained in the design by meeting safety analysis DNBR limits in performing safety analyses.

The curves of Figure 2.1-1 show the loci of points of THERMAL POWER, Reactor Coolant System pressure, and average temperature below which the calculated DNBR is no less than the design DNBR value or the average enthalpy at the vessel exit is less than the enthalpy of saturated liquid.

These curves are based on an enthalpy hot channel factor, F NH , of 1.70 (includes measurement uncertainty) and a reference cosine with a teak of 4.55 for axial power shape. An allowance is included for an increase in FA H at reduced power based on the expression:

FANH = 1.70 [1 + 0.3 (I-P)]

where P is the fraction of RATED THERMAL POWER These limiting heat flux conditions are higher than those calculated for the range of all control rods fully withdrawn to the maximum allowable control rod insertion assuming axial imbalance is within the limits of F (delta I) function of the Overtemperature trip. When the axial power imbalance is not within the tolerance, the axial power imbalance effect on the Overtemperature delta T trips will reduce the setpoints to provide protection consistent with core safety limits.

4 MILLSTONE UNIT 3 B 2-1 Amendment No. P9, 217 0964

SAFETY LIMITS BASES 2.1.2 REACTOR COOLANT SYSTEM PRESSURE The restriction of this Safety Limit protects the integrity of the Reactor Coolant System (RCS) from overpressurization and thereby prevents the release of radionuclides contained in the reactor coolant from reaching the containment atmosphere.

The reactor vessel, pressurizer, and the RCS piping, valves and fittings are designed to Section III of the ASME Code for Nuclear Power Plants which permits a maximum transient pressure of 110% (2750 psia) of design pressure.

The Safety Limit of 2750 psia is therefore consistent with the design criteria and associated Code requirements.

The entire RCS is hydrotested at 125% (3125 psia) of design pressure, to demonstrate integrity prior to initial operation.

MILLSTONE - UNIT 3 E 2-2

LBDCRLNo. 04-MP3-015 February 24, 2005 2.2 LIMTING SAFETY SYSTEM SETTINGS BASES 2.2.1 REACTOR WRPSYSTEM INSTRUMENATION SMEPOTWTS The Nominal Trip Setpoints specified in Table 22-1 ar the nominal values at which the reactor trips are set for each finctional Unitl The Allowable Values (Nominal Trip Setpoints db the calibration tolerance) are considered the Limiting Safety System Settings as identified in IOCFR5036 and have been selected to ensure that the core and Reactor Coolant System are prevented from exceeding their safety limits during normal operation and design basis anticipated operational occurrences and to assist the Engineered Safety Peatures Actuation System in mitigating the consequences of accidents. The Setpoint for a Reactor Trip System or interlock function is considered to be consistent with the nominal value when the measured "as left" Setpoint is within the administratively controlled (1)calibration tolerance identified in plant procedures (which specifies the diffnce between the Allowable Value and Nominal Trip Setpoint). Additionally, the Nominal Trip Selpoints may be adjusted in the conservative direction provided the calibration tolerance remains u.nchanged.

Measurement and Test Equipment accuracy is administratively controlled by plant procedures and is included intheplantuncertaintycalculations as defined inWCAP-10991.

OPERABILiTY determinations arc based on the use ofMeasurement and Test Equipment that conforms with the accuracy used in the plant uncertainty calculation.

The Allowable Value specified in Table 2.2-1 defines the limit beyond which a channel is inoperable. If the process rack bistable setti~g is measured within the "as Ieft" calibration tolerance, which specifies the difference between the Allowable Value and Nominal Trip Setpoint, then the channel is considered to be OPERABLE. (

The methodology, as defined in WCAP-10991 to derive the Nominal Trip Setpoints, is based upon combining al ofthe nceainties m thechanwnels. Inherent in the determiation of the Nominal Trip Setpoints are the magnitudes of these channel uncertainties. Sensors and other instumention utilized in these channels should be capable of operating within the allowances of these uncertaintymagnitudes. Occasional drift in excess of the allowance may be determined to be acceptable based an te other device performance characteristics. Device drift in excess ofthe allowance that is more than occasional, may be indicative of more serious problems and would warrant further invesbhtion.

The various reactor trip circuits automatically open the reactor trip breakers whenever a condition monitored by Cbe Reactor Trip System reaches a preset or calculated leveL In addition to the redundant channels and trains, the design approach provides Reactor Trip System fmctional diversity. The MLLSTONE - U1 T 3 B 2-3 Amendment No. 459,

2.2 LIMITING SAFETY SYSTEM SETTINGS BASES REACTOR TRIP SYSTEM INSTRUMENTATION SETPOINTS (Continued) functional capability at the specified trip setting is required for those anticipatory or diverse reactor trips for which no direct credit was assumed in the safety analysis to enhance the overall reliability of the Reactor Trip System. The Reactor Trip System initiates a turbine trip signal whenever reactor trip is initiated. This prevents the reactivity insertion that would otherwise result from excessive Reactor Coolant System cooldown and thus avoids unnecessary actuation of the Engineered Safety Features Actuation System.

Manual Reactor Trip The Reactor Trip System includes manual Reactor trip capability.

Power Range. Neutron Flux In each of the Power Range Neutron Flux channels there are two independent bistables, each with its own trip setting used for a High and Low Range trip setting. The Low Setpoint trip provides protection during subcritical and low power operations to mitigate the consequences of a power excursion beginning from low power, and the High Setpoint trip provides protection during power operations to mitigate the consequences of a reactivity excursion from all power levels.

The Low Setpoint trip may be manually blocked above P-10 (a power level of approximately 10% of RATED THERMAL POWER) and is automatically reinstated below the P-10 Setpoint.

Power Range. Neutron Flux. High Positive Rate The Power Range Positive Rate trip provides protection against rapid flux increases which are characteristic of a rupture of a control rod drive housing.

Specifically, this trip complements the Power Range Neutron Flux High and Low trips to ensure that the criteria are met for all rod ejection accidents.

MILLSTONE - t6IT 3 B 2 -4 Amendment No. JYF, Ad. 217 0965

LIMITING SAFETY SYSTEM SETTINGS BASES Intermediate and Source Range, Neutron Flux The Intermediate and Source Range, Neutron Flux trips provide core protection during reactor startup to mitigate the consequences of an uncon-trolled rod cluster control assembly bank withdrawal from a subcritical condition. These trips provide redundant protection to the Low Setpoint trip of the Power Range, Neutron Flux channels. The Source Range channels will initiate a Reactor trip at about 105 counts per second unless manually blocked when P-6 becomes active. The Intermediate Range channels will initiate a Reactor trip at a current level equivalent to approximately 25% of RATED THERMAL POWER unless manually blocked when P-10 becomes active. No credit was taken for operation of the trips associated with either the Intermediate or Source Range Channels in the accident analyses; however, their functional capability at the specified trip settings is required by this specification to enhance the overall reliability of the Reactor Trip System.

Overtemperature AT The Overtemperature AT trip provides core protection to prevent DNB for all combinations of pressure, power, coolant temperature, and axial power distribution, provided that the transient is slow with respect to piping transit delays from the core to the temperature detectors, and pressure is within the range between the Pressurizer High and Low Pressure trips. The Setpoint is automatically varied with: (1) coolant temperature to correct for temperature induced changes in density and heat capacity of water and includes dynamic compensation for piping delays from the core to the loop temperature detectors, (2) pressurizer pressure, and (3) axial power distribution. With normal axial power distribution, this Reactor trip limit is always below the core Safety Limit as shown in Figure 2.1-1. If axial peaks are greater than design, as indicated by the difference between top and bottom power range nuclear detectors, the Reactor trip is automatically reduced according to the notations in Table 2.2-1. Although a direction of conservatism is identified for the Overtemperature AT reactor trip function K? and K3 gains, the gains should be set as close as possible to the values contained in Note I to ensure that the Overtemperature AT setpoint is consistent with the assumptions of the safety analyses.

Overpower AT The Overpower AT trip provides assurance of fuel integrity (e.g., no fuel pellet melting and less than 1% cladding strain) under all possible overpower conditions, limits the required range for Overtemperature AT MILLSTONE - UNIT 3 0965 B 2-5 Amendment No. l,MP. JU,217

LIMITING SAFETY SYSTEM SETTINGS BASES trip, and provides a backup to the High Neutron Flux trip. The Setpoint is automatically varied with: (1) coolant temperature to correct for tempera-ture induced changes in density and heat capacity of water, and (2) rate of change of temperature for dynamic compensation for piping delays from the core to the loop temperature detectors, to ensure that the allowable heat genera-tion rate (kW/'ft) is not exceeded. The Overpower AT trip provides protection to mitigate the consequences of various size steam breaks as reported in WCAP-9226, "Reactor Core Response to Excessive Secondary Steam Releases."

Pressurizer Pressure In each of the pressurizer pressure channels, there are two independent bistatles, each with its own trip setting to provide for a High and Low Pressu-e trip thus liirting the pressure range in which reactor operation is permitted.

The Low Setpoint trip protects against lob pressure which could lead to DNS b, tripping the reactor in the event of a loss of reactor coolant pressure.

On decreasing power the Low Setpoint trip is automatically blocked by P-7 (a power level of approximately 10% of RATED THERMAL POWER with turbine impulse chamber pressore at approximately 10% of full power equivalent); and on increasing power, automatically reinstated by P-7.

The High Setpoint trip functions in conjunction with the pressurizer relief ano safety valves to protect the Reactor Coolant System against system overpressure.

Pressurizer Watee Level The Pressurizer Water Level High trip is provided to prevent water relief through the pressurizer safety valves. On decreasing power the Pressurizer High Water Level trip is automatically blocked by P-7 (a power level of approxi-mately 10% of RATED THERMAL POWER with a turbine impulse chamber pressure at approximately 10% of full power equivalent); and on increasing power, auto-matically reinstated by P-7. -

Reactor Coolant Flow The Reactor Coolant Flow Low trip provides core protection to prevent DNB by mitigating the consequences of a loss of flow resulting from the loss of one or more reactor coolant pumps.

On increasing power above P-7 (a power level of approximately 10% of RATED THERMAL POWER or a turbine impulse chamber pressure at approximately 10%

of full power equivalent), an automatic Reactor trip will occur if the flow in more than one loop drops below 90% of nominal full loop flow. Above P-8 (a power level of approximately 38% of RATED THERMAL POWER) an automatic Reactor trip will occur if the flow in any single loop drops below 90% of nominal full loop flow. Conversely, on decreasing power between P-8 and the P-7 an automatic Reactor trip will occur on low reactor coolant flow in more than one loop and below P-7 the trip function is automatically blocked.

MILLSTONE - UNIT 3 B 2-6

LIMITING SAFETY SYSTEM SETTINGS BASES Steam Generator Water Level The Steam Generator Water Level Low-Low trip protects the reactor from loss of heat sink in the event of a sustained steam/feedwater flow mismatch resulting from loss of normal feedwater. The specified Setpoint provides allowances for starting delays of the Auxiliary Feedwater System.

Low Shaft Speed - Reactor Coolant Pumps The Low Shaft Speed - Reactor Coolant Pumps trip provides core protection to prevent DNB in the event of a sudden significant decrease in reactor coolant pump speed (with resulting decrease in flow) on two reactor coolant pumps in any two operating reactor coolant loops. The trip setpoint ensures that a reactor trip will be generated, considering instrument errors and response times, in sufficient time to allow the DNBR to be maintained greater than the design above limit following a four-pump loss of flow event.

Turbine Trin A Turbine trip initiates a Reactor trip. On decreasing power the Reactor trip from the Turbine trip is automatically blocked by P-9 (a power level of approximately 50% of RATED THERMAL POWER); and on increasing power, reinstated automatically by P-9.

Safety Injection Input from ESF If a Reactor trip has not already been generated by the Reactor Trip System instrumentation, the ESF automatic actuation logic channels will initiate Reactor trip upon any signal which initiates a Safety Injection.

The ESF instrumentation channels which initiate a Safety Injection signal are shown in Table 3.3-3.

Reactor Trip System Interlocks The Reactor Trip System interlocks perform the following functions:

P-6 On increasing power, P-6 becomes active above the Interlock Allowable Value specified on Table 2.2-1 to allow the manual block of the Source Range trip (i.e., prevents premature block of the Source Range trip during reactor startup) and deenergizes the high voltage to the detectors. On decreasing power during a reactor shutdown, Source Range Level trips are automatically reactivated and high voltage restored when P-6 deactivates. The P-6 deactivation will occur at a value below its activation value and may be calibrated to occur below the P-6 Interlock Allowable Value specified on Table 2.2-1 to prevent overlap and chatter based upon the expected bistable drift.

P-7 On increasing power P-7 automatically enables Reactor trips on low flow inmore than one reactor coolant loop, reactor coolant pump low shaft speed, pressurizer low pressure and pressurizer high level. On decreasing power, the above listed trips are automatically blocked.

MILLSTONE - UNIT 3 B 2-7 Revised by NRC Letter 0548 dated September 29. 1997

. . .re QW ,; -flo 7

LBDCR 04-MP3-010 November 18, 2004 LDEM SAY STEM BS-N BASES Reactor fp Systern Interlocks (Continued P-8 On increasing power, P-8 automatically enables Reactor trips on low flow in one or more reactor coolant loops. On decreasing power, the P-8 automatically blocks the above listed trips.

P-9 On increasing power, P-9 automatically enables Reactor trip on lbine trip. On decreasing power, P-9 automatically blocks Reactor trip on Trbine trip.

P-1O On increasing power, P-10 provides input to P-7 to ensure that Reactor llrips on low flow in more than one reactor coolant loop, reactor coolant pump low shaft speed, prsurizer low pressure and pressurizer high level are active when power reaches 11%. It also allows the manual block of the Intermediate Range trip and the Low Setpoint Power Range trip; and automatically blocds the Source Range trip and deeergizes the Source Range high voltage power.

On decreasing power, P-IO resets to automatically reactivate the Intermediate Range trip and the Low Setpoint Power Range trip before power drops below 9%. It also provides input to reset P-7.

P-13 On increasing power, P-13 provides input to P-7 to ensure that Reactor trips on low flow in more than one reactor coolant loop, reactor coolant pump low shaf sped, pressurizer low pressure and pressurizer high level are active when power reaches 10%.

On decreasing power, P-13 resets when power drops below 10% and provides input, along with P-10, to reset P-7.

MILLSTONE - UNIT 3 B2-8 Amendment No. 8S, 24-, M,

, xeQ aiOC4L & 3-G5 a65- ,66

SECTIONS 3.0 AND 4.0 LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS

J/4 LIMI1ING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS 3/4.0 APPLICABILITY LIMITING CONDITION FOR OPERATION 3.0.1 Compliance with the Limiting Conditions for Operation contained in the succeeding specifications is required during the OPERATIONAL MODES or other conditions specified therein; except that upon failure to meet the Limiting Conditions for Operation, the associated ACTION requirements shall be met, except as provided in Specification 3.0.5.

3.0.2 Noncompliance with a specification shall exist when the requirements of the Limiting Condition for Operation and associated ACTION requirements are not met within the specified time intervals, except as provided in Specification 3.0.5. If the Limiting Condition for Operation is restored prior to expiration of the specified time intervals, completion of the ACTION requirements is not required. i 3.0.3 When a Limiting Condition for Operation is not met, except as provided in the associated ACTION requirements, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> action shall be initiated to place the unit in a MODE in which the specification does not apply by placing it, as applicable, in:

a. At least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />,

b. At least HOT SHUTDOWN within the following 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />, and

c. At least COLD SHUTDOWN within the subsequent 24 hours1 days <br />0.143 weeks <br />0.0329 months <br />.

Where corrective measures are completed that permit operation under the ACTION requirements, the action may be taken in accordance with the specified time limits as measured from the time of failure to meet the Limiting Condition for Operation. Exceptions to these requirements are stated in the individual specifications.

This specification is not applicable in MODE 5 or 6.

3.0.4 Entry into an OPERATIONAL MODE or other specified condition shall not be made when the conditions for the Limiting Condition for Operation are not met and the associated ACTION requires a shutdown if they are not met within a specified time interval. Entry into an OPERATIONAL MODE or specified condition may be made in accordance with ACTION requirements when conformance to them permit continued operation of the facility for an unlimited period of time. This provision shall not prevent passage through or to OPERATIONAL MODES as required to comply with ACTION requirements. Exceptions to these requirements are stated in the individual specifications.

3.0.5 Equipment removed from service or declared inoperable to comply with ACTIONS may be returned to service under administrative control solely to perform testing required to demonstrate its OPERABILITY or the OPERABILITY of other equipment. This is an exception to Specifications 3.0.1 and 3.0.2 for the system returned to service under administrative controls to perform the testing required to demonstrate OPERABILITY.

4.0.1 Surveillance Requirements shall be met during the OPERATIONAL MODES or other conditions specified for individual Limiting Conditions for Operation unless otherwise stated in an individual Surveillance Requirement. Failure to meet a Surveillance, whether such failure is experienced during the performance MILLSTONE - UNIT 3 3/4 0-1 Amendment No. Ad, 97, 77y, 213 0912 5 2

_/4 LIMnlNtIU CUNDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS 3/4.0 APPLICABILITY LTMITING CONDITION FOR OPERATION of the Surveillance or between performances of the Surveillance, shall be failure to meet the Limiting Condition for Operation. Failure to perform a Surveillance within the specified surveillance interval shall be failure to meet the Limiting Condition for Operation except as provided in Specification 4.0.3. Surveillances do not have to be performed on inoperable equipment or variables outside specified limits.

4.0.2 Each Surveillance Requirement shall be performed within the specified time interval with a maximum allowable extension not to exceed 25% of the surveillance interval.

4.0.3 If it is discovered that a Surveillance was not performed within its specified surveillance interval, then compliance with the requirement to declare the Limiting Condition for Operation not met may be delayed, from the time of discovery, up to 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> or up to the limit of the specified surveillance interval, whichever is greater. This delay period is permitted to allow performance of the Surveillance. A risk evaluation shall be performed for any Surveillance delayed greater than 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> and the risk impact shall be managed.

If the Surveillance is not performed within the delay period, the Limiting Condition for Operation must immediately be declared not met, and the applicable Condition(s) must be entered.

When the Surveillance is performed within the delay period and the Surveillance is not met, the Limiting Condition for Operation must immediately be declared not met, and the applicable Condition(s) must be entered.

4.0.4 Entry into an OPERATIONAL MODE or other specified condition shall not be made unless the Surveillance Requirement(s) associated with the Limiting Condition for Operation has been performed within the stated surveillance interval or as otherwise specified. This provision shall not prevent passage through or to OPERATIONAL MODES as required to comply with ACTION requirements.

4.0.5 Surveillance Requirements for inservice inspection and testing of ASME Code Class 1, 2, and 3 components shall be applicable as follows:

a. Inservice inspection of ASME Code Class 1, 2, and 3 components and inservice testing of ASME Code Class 1, 2, and 3 pumps and valves shall be performed in accordance with Section XI of the ASME Boiler and Pressure Vessel Code and applicable Addenda as required by 10 CFR Part 50, Section 50.55a;

h. Surveillance intervals specified in Section XI of the ASME Boiler and Pressure Vessel Code and applicable Addenda for the inservice inspection and testing activities required by the ASME Boiler and Pressure Vessel Code and applicable Addenda shall be applicable as follows in these Technical Specifications:

MILLSTONE 0912

- UNIT 3 3/4 0-2 Amendment No. 9F, 97, J19, 77y, 213

ArFULlAIULI I Y LIMITING CONDITION FOR OPERATION (Continued)

ASME Boiler and Pressure Vessel Required frequencies for Code and applicable Addenda performing inservice terminology for inservice inspection and testing inspection and testing activities activities Weekly At least once per 7 days Monthly At least once per 31 days Quarterly or every 3 months At least once per 92 days Semiannually or every 6 months At least once per 184 days Every 9 months At least once per 276 days Yearly or annually At least once per 366 days Biennially or every 2 years At least once per 731 days

c. The provisions of Specification 4.0.2 are applicable to the above required frequencies for performing inservice inspection and testing activities;

d. Performance of the above inservice inspection and testing activities shall be in addition to other specified Surveillance Requirements; and

e. Nothing in the ASME Boiler and Pressure Vessel Code shall be construed to supersede the requirements of any Technical Specification.

MILLSTONE - UNIT 3 3/4 0-3 Amendment No. Ad, 97, 77, Add, 0912 l71, 213

3/4.1 REACTIVITY CONTROL SYSTEMS 3/4.1.1.1 BORATION CONTROL SHUTDOWN MARGIN - MODES 1 AND 2 LIMITING CONDITION FOR OPERATION 3.1.1.1.1 The SHUTDOWN MARGIN shall be within the limits specified in the Core Operating Limits Report (COLR).

APPLICABILITY: MODES I and 2*.

ACTION:

With the SHUTDOWN MARGIN not within the limits specified in the COLR, immediately initiate and continue boration at greater than or equal to 33 gpm of a solution containing greater than or equal to 6600 ppm boron or equivalent until the required SHUTDOWN MARGIN is restored.

SURVEILLANCE REQUIREMENTS 4.1.1.1.1 The SHUTDOWN MARGIN shall be determined to be within the limits specified in the COLR:

a. Within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> after detection of an inoperable control rod(s) and at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> thereafter while the rod(s) is inoperable. If the inoperable control rod is immovable or untrippable, the above required SHUTDOWN MARGIN shall be verified acceptable with an increased allowance for the withdrawn worth of the immovable or untrippable control rod(s);

b. When in MODE I or MODE 2 with Kcff greater than or equal to I at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> by verifying that control bank withdrawal is within the limits of Specification 3.1.3.6;

c. When in MODE 2 with Keff less than 1, within 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> prior to achieving reactor criticality by verifying that the predicted critical control rod position is within the limits of Specification 3.1.3.6;

d. Prior to initial operation above 5% RATED THERMAL POWER after each fuel loading, by consideration of the factors of Specification 4.1.1.1.2, with the control banks at the maximum insertion limit of Specification 3.1.3.6; and

• See Special Test Exceptions Specification 3.10.1.

MILLSTONE; - UNIT 3 3/4 1-1 Amendment No. 60, 4-3, 24-7, 218

REACTIVITY CONTROL SYSTEMS SURVEILLANCE REOMIREMENTS (Continued) 4.1.1.1.2 The overall core reactivity balance shall be compared to predicted values to demonstrate agreement within +/- 1% Ak/k at least once per 31 Effec-tive Full Power Days (EFPD). This comparison shall consider at least the following factors:

1) Reactor Coolant System boron concentration,

2) Control rod position,

3) Reactor Coolant System average temperature,

4) Fuel burnup based on gross thermal energy generation,

5) Xenon concentration, and

6) Samarium concentration.

The predicted reactivity values shall be adjusted (normalized) to correspond to the actual core conditions prior to exceeding a fuel burnup of 60 EFPD after each fuel loading.

MILLSTONE - UNIT 3 3/4 1-2 Amendment No.60 0007 ... ....,-di;,^

3/4.1 REACTIVITY CONTROL SYSTEMS 3/4.1.1 BORATION CONTROL SHUTDOWN MARGIN - MODES 3.4 AND 5 LOOPS FILLED LIMITING CONDITION FOR OPERATION 3.1.1.1.2 The SHUTDOWN MARGIN shall be within the limits specified in the Core Operating Limits Report (COLR).*

APPLICABILITY: MODES 3,4 and 5 ACTION:

With the SHUTDOWN MARGIN less than the required value, immediately initiate and continue boration at greater than or equal to 33 gpm of a solution containing greater than or equal to 6600 ppm boron or equivalent until the required SHUTDOWN MARGIN is restored.

SURVEILLANCE REQUIREMENTS 4.1.1.1.2.1 The SHUTDOWN MARGIN shall be determined to be within the limits specified in the COLR:

a. Within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> after detection of an inoperable control rod(s) and at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> thereafter while the rod(s) is inoperable. If the inoperable control rod is immovable or untrippable, the above required SHUTDOWN MARGIN shall be verified acceptable with an increased allowance for the withdrawn worth of the immovable or untrippable control rod(s); and

b. At least once per 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> by consideration of the following factors:

I. Reactor Coolant System boron concentration,

2. Control rod position,

3. Reactor Coolant System average temperature,

4. Fuel burnup based on gross thermal energy generation,

5. Xenon concentration, and

6. Samarium concentration.

4.1.1.1.2.2 Valve 3CHS-V305 shall be verified closed and locked at least once per 31 days.

• Additional SHUTDOWN MARGIN requirements, if required, are given in Specification 3.3.5.

MILLSTONE - UNIT 3 3/4 1-3 Amendment No. 60, 44-3, 4, 2W, 218

THIS PAGE INTENTIONALLY LEFT BLANK MILLSTONE - UNIT 3 34 1-4 Amendment No. X,29, a , 60, 64, 241, 218

This page intentionally left blank.

MILLSTONE - UNIT 3 3/4 1-5 Amendment No. B7, fo, 0968 6a. B7. 194. 7.17

THIS PAGE INTENTIONALLY LEFT BLANK MILLSTONE - UNIT 3 3/4 1-6 AmendmentNo. 60,--64, 218

THIS PAGE INTENTIONALLY LEFT BLANK MILLSTONE - UNIT 3 3/4 1-7 Amendment No. 6, 4-64, 218

REACTIVITY CONTROL SYSTEMS SHUTDOWN MARGIN - COLD SHUTDOWN - LOOPS NOT FILLED LIMITING CONDITION FOR OPERATION 3.1.1.2 The SHUTDOWN MARGIN shall be greater than or equal to

a. the limits specified in the CORE OPERATING LIMITS REPORT (COLR) for MODE 5 with RCS loops not filled* or

b. the limits specified in the COLR for MODE 5 with RCS loops filled* with the chemical and volume control system (CVCS) aligned to preclude reactor coolant system boron concentration reduction.

APPLICABILITY: MODE 5 LOOPS NOT FILLED ACTION:

a. With the SHUTDOWN MARGIN less than the above, immediately initiate and continue boration at greater than or equal to 33 gpm of a solution containing greater than or equal to 6600 ppm boron or equivalent until the required SHUTDOWN MARGIN is restored.

b. With the CVCS dilution flow paths not closed and secured in position in accordance with Specification 3.1.1.2(b), immediately close and secure the paths or meet the limits specified in the COLR for MODE 5 with RCS loops not filled.

SURVEILLANCE REQUIREMENTS 4.1.1.2.1 The SHUTDOWN MARGIN shall be determined to be within the limits specified in the COLR:

a. Within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> after detection of an inoperable control rod(s) and at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> thereafter while the rod(s) is inoperable. If the inoperable control rod is immovable or untrippable, the SHUTDOWN MARGIN shall be verified acceptable with an increased allowance for the withdrawn worth of the immovable or untrippable control rod(s); and

b. At least once per 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> by consideration of the following factors:

I. Reactor Coolant System boron concentration,

2. Control rod position,

3. Reactor Coolant System average temperature,

4. Fuel burnup based on gross thermal energy generation,

• Additional SHUTDOWN MARGIN requirements, if required, are given in Specification 3.3.5.

MILLSTONE - UNIT 3 3/4 1-8 Amendment No. 6,9,9 , --64-, 218

REACTIVITY CONTROL SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

5) Xenon concentration, and

6) Samarium concentration.

4.1.1.2.2 At least once per 31 days the following valves shall be verified closed and locked. The valves may be opened on an intermittent basis under administrative controls except as noted.

Valve Number Valve Function

1. V304(Z-) Primary Grade Water Closed to CVCS

2. V120(Z-) Moderating Hx Outlet Closed

3. V147(Z-) BTRS Outlet Closed

4. V797(Z-) Failed Fuel Monitoring Closed Flushing S. V100(Z-) Resin Sluice, CVCS Cation Closed Bed Demineralizer

6. V571(Z-) Resin Sluice, CVCS Cation Closed Bed Demineralizer

7. VYll(Z-) Resin Sluice, CVCS Cation Closed Bed Demineralizer

8. V112(Z-) Resin Sluice, CYCS Cation Closed Bed Demineralizer

9. V98(Z-)/V99(Z-) Resin Sluice, CVCS Mixed Closed Bed Demineralizer

10. V569(Z-)/V570(Z-) Resin Sluice, CVCS Mixed Closed Bed Demineralizer

11. V107(Z-)/V109(Z-) Resin Sluice, CVCS Mixed Closed Bed Demineralizer

12. V108(Z-)/VllO(Z-) Resin Sluice, CVCS Mixed Closed Bed Demineralizer

13. V305(Z-)* Primary Grade Water Closed to Charging Pumps

• This valve may not be opened under administrative controls. I MILLSTONE - UNIT 3 3/4 1-8a Amendment No. 99 0209

.- ' 1 C f r,

THIS PAGE INTENTIONALLY LEFT BLANK MILLSTONE - UNIT 3 3/4 1-9 Amendment No. 60, 99, 464,218

REACTIVITY CONTROL SYSTEMS MODERATOR TEMPERATURE COEFFICIENT LIMITING CONDITION FOR OPERATION 3.1.1.3 The moderator temperature coefficient (MTC) shall be within the limits specified in the CORE OPERATING LIMITS REPO&TS (COLR). The maximum upper limit shall be less positive than +0.5 x 10 Ak/k/F for all the rods withdrawn, beginning of cycle life (BOL), condition for power levels up to 70% RATED THERMAL POWER with a linear ramp to 0 Ak/k/tF at 100% RATED THERMAL POWER.

APPLICABILITY: BOL - MODES 1 and 2* only**.

End of Cycle life (EOL) Limit - MODES 1, 2, and 3 only**.

ACTION:

a. With the MTC more positive than the BOL limit of Specification 3.1.1.3 above, operation in MODES 1 and 2 may proceed provided:

1. Control rod withdrawal limits are established and maintained sufficient to restore the MTC to less positive than the above limits within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> or be in HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />. These withdrawal limits shall be in addition to the insertion limits of Specification 3.1.3.6;

2. The control rods are maintained within the withdrawal limits established above until a subsequent calculation verifies that the MTC has been restored to within its limit for the all rods withdrawn condition; and

3. A Special Report is prepared and submitted to the Commission, pursuant to Specification 6.9.2, within 10 days, describing the value of the measured MTC, the interim control rod withdrawal limits, and the predicted average core burnup necessary for restoring the positive MTC to within its limit for the all rods withdrawn condition.

b. With the MTC more negative than the EOL limit specified in the COLR, be in HOT SHUTDOWN within 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />.

• With Keff greater than or equal to 1.

• • See Special Test Exceptions Specification 3.10.3.

MILLSTONE - UNIT 3 3/4 1-10 Amendment No. 60 0007

• . I; r-,i , a/.

REACTIVITY CONTROL SYSTEMS SURVEILLANCE REQUIREMENTS 4.1.1.3 The MTC shall be determined to be within its limits during each fuel cycle as follows:

a. The MTC shall be measured and compared to the BOL limit of Specification 3.1.1.3, above, prior to initial operation above 5%

of RATED THERMAL POWER, after each fuel loading; and

b. The MTC shall be measured at any THERMAL POWER and compared to the 300 ppm surveillance limit specified in the COLR (all rods withdrawn, RATED THERMAL POWER condition) within 7 EFPD after reaching an equilibrium boron concentration of 300 ppm. In the event this comparison indicates the MTC is more negative than the 300 ppm surveillance limit specified in the COLR, the MTC shall be remeasured, and compared to the EOL MTC limit specified in the COLR, at least once per 14 EFPD during the remainder of the fuel cycle.

MILLSTONE - UNIT 3 0a07 3/4 1-11 Amendment No. fl,60 I s.. - ; I

REACTIVITY CONTROL SYSTEMS MINIMUM TEMPERATURE FOR CRITICALITY LIMITING CONDITION FOR OPERATION 3.1.1.4 The Reactor Coolant System lowest operating loop temperature (Tayg) shall be greater than or equal to 5510F.

APPLICABILITY: MODES 1 and 2* **.

ACTION:

With a Reactor Coolant System operating loop temperature (Tavg) less than 551F, restore Tavg to within its limit within 15 minutes or be in HOT STANDBY within the next 15 minutes.

SURVEILLANCE REQUIREMENTS 4.1.1.4 The Reactor Coolant System temperature (Tavg) shall be determined to be greater than or equal to 551PF:

a. Within 15 minutes prior to achieving reactor criticality, and

b. At least once per 30 minutes when the reactor is critical and the Reactor Coolant System Tavg is less than 561 0F with the Tavg-Tref Deviation Alarm not reset.

• With Keff greater than or equal to 1.

• • See Special Test Exceptions Specification 3.10.3.

MILLSTONE - UNIT 3 oaa7 3/4 1-12 Amendment No. 11. 60

t. :; ; . .J I.

This Page Intentionally Left Blank MILLSTONE - UNIT 3 3/4 1-13 Amendment No. A, W7, 197 0774

This Page Intentionally Left Blank MILLSTONE - UNIT 3 3/4 1-14 Amendment No. Ad, A, ,lZ, IF7, 197 0774

This Page Intentionally Left Blank MILLSTONE - UNIT 3 3/4 1-15 Amendment No. Hi, Fi, Gil. 197 0774 WI

This Page Intentionally Left Blank MILLSTONE - UNIT 3 3/4 1-16 Amendment No. PO, Gus, O, 197

This Page Intentionally Left Blank MILLSTONE - UNIT 3 3/4 1-17 Amendment No. Yp, 71Th 197 0774

This Page Intentionally Left Blank MILLSTONE - UNIT 3 0774 3/4 1-18 Amendment No. F , PI. 7f, 197

This Page Intentionally Left Blank MILLSTONE - UNIT 3 3/4 1-19 Amendment No. f,197 0774

REACTIVITY CONTROL SYSTEMS 3/4.1.3 MOVABLE CONTROL ASSEMBLIES GROUP HEIGHT LIMITING CONDITION FOR OPERATION 3.1.3.1 All full-length shutdown and control rods shall be OPERABLE and positioned within +/-12 steps (indicated position) of their group step counter demand position.

APPLICABILITY: MODES 1* and 2*.

ACTION:

a. With one or more full-length rods inoperable due to being immovable as a result of excessive friction or mechanical interference or known to be untrippable, determine that the SHUTDOWN MARGIN requirement of Specification 3.1.1.1 is satisfied within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and be in HOT STANDBY within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />.

b. With one full-length rod trippable but inoperable due to causes other than addressed by ACTION a., above, or misaligned from its group step counter demand height by more than +12 steps (indicated position), POWER OPERATION may continue provided that within 1 hour:

1. The rod is restored to OPERABLE status within the above alignment requirements, or

2. The rod is declared inoperable and the remainder of the rods in the group with the inoperable rod are aligned to within

+12 steps of the inoperable rod while maintaining the rod sequence and insertion limits of Specification 3.1.3.6. The THERMAL POWER level shall be restricted pursuant to Specification 3.1.3.6 during subsequent operation, or

3. The rod is declared inoperable and the SHUTDOWN MARGIN requirement of Specification 3.1.1.1 is satisfied. POWER OPERATION may then continue provided that:

a) A reevaluation of each accident analysis of Table 3.1-1 is performed within 5 days; this reevaluation shall confirm that the previously analyzed results of these accidents remain valid for the duration of operation under these conditions; b) The SHUTDOWN MARGIN requirement of Specification 3.1.1.1 is determined at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />;

• See Special Test Exceptions Specifications 3.10.2 and 3.10.3.

MILLSTONE - UNIT 3 3/4 1-20 Amendment No. f,60 0007

REACTIVITY CONTROL SYSTEMS LIMITING CONDITION FOR OPERATION ACTION (Continued) c) A power distribution map is obtained from the movable incore detectors and FQ(Z) and FN.H are verified to be within their limits within 72 hours3 days <br />0.429 weeks <br />0.0986 months <br />; and d) THERMAL POWER level is reduced to less than or equal to 75% of RATED THERMAL POWER within the next hour and within the following 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> the High Neutron Flux Trip Setpoint is reduced to less than or equal to 85%

of RATED THERMAL POWER.

c. With more than one rod trippable but inoperable due to causes other than addressed by ACTION a. above, POWER OPERATION may continue provided that:

1. Within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, the remainder of the rods in the bank(s) with the inoperable rods are aligned to within +12 steps of the inoperable rods while maintaining the rod sequence and insertion limits of Specification 3.1.3.6. The THERMAL POWER level shall be restricted pursuant to Specification 3.1.3.6 during subsequent operation, and

2. The inoperable rods are restored to OPERABLE status within 72 hours3 days <br />0.429 weeks <br />0.0986 months <br />.

d. With more than one rod misaligned from its group step counter demand height by more than +12 steps (indicated position), be in HOT STANDBY within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />.

SURVEILLANCE REQUIREMENTS 4.1.3.1.1 The position of each full-length rod shall be determined to be within the group demand limit by verifying the individual rod positions at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> except during time intervals when the rod position deviation monitor is inoperable, then verify the group positions at least once per 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />.

4.1.3.1.2 Each full-length rod not fully inserted in the core shall be determined to be OPERABLE by movement of at least 10 steps in any one direction at least once per 92 days.

MILLSTONE - UNIT 3 3/4 1-21 Amendment No. y?, Fp, 171, 217 0969

TABLE 3.1-1 ACCIDENT ANALYSES REQUIRING REEVALUATION IN THE EVENT OF AN INOPERABLE FULL-LENGTH ROD Rod Cluster Control Assembly Insertion Characteristics Rod Cluster Control Assembly Misalignment Loss of Reactor Coolant from Small Ruptured Pipes or from Cracks in Large Pipes Which Actuates the Emergency Core Cooling System Single Rod Cluster Control Assembly Withdrawal at Full Power Major Reactor Coolant System Pipe Ruptures (Loss-of-Coolant Accident)

Major Secondary Coolant System Pipe Rupture Rupture of a Control Rod Drive Mechanism Housing (Rod Cluster Control Assembly Ejection)

MILLSTONE - UNIT 3 0007 3/4 1-22 Amendment No. Fp,60

...I I .

REACTIVITY CONTROL SYSTEMS POSITION INDICATION SYSTEMS - OPERATING IIITINA CnNnfTTInN AFR nPFRATTON 3.1.3.2 The Digital Rod Position Indication System and the Demand Position Indication System shall be OPERABLE and capable of determining the control rod positions within +/-12 steps.

APPLICABILITY: MODES 1 and 2.

ACTION:

a. With a maximum of one digital rod position indicator per bank inoperable:

1. Determine the position of the nonindicating rod(s) indirectly by the movable incore detectors at least once per 8 hours0.333 days <br />0.0476 weeks <br />0.011 months <br /> and immediately after any motion of the nonindicating rod which exceeds 24 steps in one direction since the last determination of the rod's position, or

2. Reduce THERMAL POWER to less than 50% of RATED THERMAL POWER within 8 hours0.333 days <br />0.0476 weeks <br />0.011 months <br />.

b. With a maximum of one demand position indicator per bank inoperable:

1. Verify that all digital rod position indicators for the affected bank are OPERABLE and that the most withdrawn rod and the least withdrawn rod of the bank are within a maximum of 12 steps of each other at least once per 8 hours0.333 days <br />0.0476 weeks <br />0.011 months <br />, or

2. Reduce THERMAL POWER to less than 50% of RATED THERMAL POWER within 8 hours0.333 days <br />0.0476 weeks <br />0.011 months <br />.

SURVEILLANCE REQUIREMENTS 4.1.3.2.1 Each digital rod position indicator shall be determined to be OPERABLE by verifying that the Demand Position Indication System and the Digital Rod Position Indication System agree within 12 steps at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> except during time intervals when the rod position deviation monitor is inoperable, then compare the Demand Position Indication System and the Digital Rod Position Indication System at least once per 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />.

4.1.3.2.2 Each of the above required digital rod position indicator(s) shall be determinded to be OPERABLE by verifying that the digital rod position indicators agree with the demand position indicators within 12 steps when exercised over the full-range of rod travel at least once per 24 months.

MILLSTONE - UNIT 3 3/4 1-23 Amendment No. pp, F9, Zpp, 0970 7P7,217

THIS PAGE INTENTIONALLY LEFT BLANK MILLSTONE - UNIT 3 3/4 1-24 Amendment No. ip, 17Z, i0%. 207 0806 JUL S 4Be2

REACTIVITY CONTROL SYSTEMS ROD DROP TIME LIMITING CONDITION FOR OPERATION 3.1.3.4 The individual full -Jieignh (-zu.doi.io end controIll morop tI'he from the fully withdrawn position Shall be less than equal

'or to 2.7 seconaIS from beginning of decay of s-tational-,, :p-iiroer- coil .l taJ e dmnpot d entri wi th:

a. Te..,greater than or equal to 551 F. and

b. All reactor coolant pumps operating.

APPLICABILITY: MODES 1 and 2.

ACTION:

a. With the drop time of any full-length rod determined to exceed the above limit, restore the rod drop time to within the above limit prior to proceeding to MODE 1 or 2.

b. With the rod drop times within limits but determined with three reactor coolant pumps operating, operation may proceed provided THERMAL POWER is restricted to less than or equal to 65%,' of RATED THERMAL POWER with the reactor coolant stop valves in the nonoperating loop closed.

SURVEILLANCE REQUIREMENTS 4.1.3.4 The rod drop time of full-length rods shall be demonstrated through measurement prior to reactor criticality:

a. For all rods following each removal of the reactor vessel head,

b. For specifically affected individual rods following any maintenance on or modification to the Control Rod Drive System which could affect the drop time of those specific rods, and

c. At least once per 24 months.

MILLSTONE - UNIT 3 3/4 1-25 Amendment No. 0, fly, 206 0843

REACTIVITY CONTROL SYSTEMS SHUTDOWN ROD INSERTION LIMIT LIMITING CONDITION FOR OPERATION 3.1.3.5 All shutdown rods shall be limited in physical insertion as specified in the core operating limits report (COLR).

APPLICABILITY: MODES 1* and 2* **.

ACTION:

With a maximum of one shutdown rod inserted beyond the insertion limits specified in the COLR except for surveillance testing pursuant to Specification 4.1.3.1.2, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> either:

a. Restore the rod to within the limit specified in the COLR, or

b. Declare the rod to be inoperable and apply Specification 3.1.3.1.

SURVEILLANCE REQUIREMENTS 4.1.3.5 Each shutdown rod shall be determined to be within the insertion limits specified in the COLR:

a. Within 15 minutes prior to withdrawal of any rods in Control Bank A, B, C, or 0 during an approach to reactor criticality, and

b. At least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> thereafter.

• See Special Test Exceptions Specifications 3.10.2 and 3.10.3.

• • With Keff greater than or equal to 1.

MILLSTONE - UNIT 3 3/4 1-26 Amendment No. 60 000.

REACTIVITY CONTROL SYSTEMS CONTROL ROD INSERTION LIMITS LIMITING CONDITION FOR OPERATION 3.1.3.6 The control banks shall be limited in physical insertion as specified in the core operating limits report (COLR).

APPLICABILITY: MODES 1* and 2* **.

With the control banks inserted beyond the insertion limits specified in the COLR, except for surveillance testing pursuant to Specification 4.1.3.1.2:

a. Restore the control banks to within the limits within 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br />, or

b. Reduce THERMAL POWER within 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> to less than or equal to that fraction of RATED THERMAL POWER which is allowed by the bank posi-tion using the insertion limits specified in the COLR, or

c. Be in at least HOT STANDBY within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />.

SURVEILLANCE REOUIREMENTS 4.1.3.6 The position of each control bank shall be determined to be within the insertion limits at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> except during time intervals when the rod insertion limit monitor is inoperable, then verify the individual rod positions at least once per 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />.

• See Special Test Exceptions Specifications 3.10.2 and 3.10.3.

• • With Keff greater than or equal to 1.

MILLSTONE - UNIT 3 0007 3/4 1-27 Amendment No. g ,60

.I '. ' i - .' ! I

3/4.2 POWER DISTRIBUTION LIMITS 3/4.2.1 AXIAL FLUX DIFFERENCE I I TMTTTN9 (CnNllTTTlfN FMP nPFRATTnN 3.2.1.1 The indicated AXIAL FLUX DIFFERENCE (AFD) shall be maintained within:

a. The limits specified in the CORE OPERATING LIMITS REPORT (COLR) for Relaxed Axial Offset Control (RAOC) operation, or

b. Within the target band about the target flux difference during base load operation, specified in the COLR.

APPLICABILITY: MODE I above 50% RATED THERMAL POWER*.

ACTION:

a. For RAOC operation with the indicated AFD outside of the applicable limits specified in the COLR,

1. Either restore the indicated AFD to within the COLR specified limits within 15 minutes, or

2. Reduce THERMAL POWER to less than 50% of RATED THERMAL POWER within 30 minutes and reduce the Power Range Neutron Flux--

High Trip setpoints to less than or equal to 55% of RATED THERMAL POWER within the next 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />.

b. For base load operation above APLND with the indicted AFD outside of the applicable target band about the target flux differences:

1. Either restore the indicated AFD to within the COLR specified target band within 15 minutes, or

2. Reduce THERMAL POWER to less than APLND of RATED THERMAL POWER and discontinue base load operation within 30 minutes.

c. THERMAL POWER shall not be increased above 50% of RATED THERMAL POWER unless the indicated AFD is within the limits specified in the COLR.

• See Special Test Exception 3.10.2 MILLSTONE - UNIT 3 3/4 2-1 Amendment No. fp, pp,217 0971

POWER DISTRIBUTION LIMITS SURVEILLANCE REQUIREMENTS 4.2.1.1.1 The indicated AFD shall be determined to be within its limits during POWER OPERATION above 50% of RATED THERMAL POWER by:

a. Monitoring the indicated AFD for each OPERABLE excore channel at least once per 7 days when the AFD Monitor Alarm is OPERABLE:

b. Monitoring and logging the indicated AFD for each OPERABLE excore channel at least once per hour for the first 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> and at least once per 30 minutes thereafter, when the AFD Monitor Alarm is inoperable. The logged values of the indicated AFD shall be assumed to exist during the interval preceding each logging.

4.2.1.1.2 The indicated AFD shall be considered outside of its limits when two or more OPERABLE excore channels are indicating the AFD to be outside the limits.

4.2.1.1.3 When in base load operation, the target flux difference of each OPERABLE excore channel shall be determined by measurement at least once per 92 Effective Full Power Days. The provisions of Specification 4.0.4 are not applicable.

4.2.1.1.4 When in base load operation, the target flux difference shall be updated at least once per 31 Effective Full Power Days by either determining the target flux difference in conjunction with the surveillance requirements of Specification 4.2.1.1.3 or by linear interpolation between the most recently measured value and the calculated value at the end of cycle life.

The provisions of Specification 4.0.4 are not applicable.

MILLSTONE - UNIT 3 3/4 2-2 Amendment No. 0,60 0011 . A -

This page intentionally left blank.

MILLSTONE - UNIT 3 3/4 2-3 Amendment No. Hi, F9, 217 0972

This page intentionally left blank.

MILLSTONE - UNIT 3 3/4 2-4 Amendment No. FP, fq, 217 0972

POWER DISTRIBUTION LIMITS 3/4.2.2 HEAT FLUX HOT CHANNEL FACTOR - FQELS LIMITING CONDITION FOR OPERATION I 3.2.2.1 F,(Z) shall be limited by the following relationships:

F0RTP FQ(Z) <

• K(Z) for P > 0.5 P

FQ(Z) < ° K(Z) for P < 0.5 FaTP = the FQ limit at RATED THERMAL POWER (RTP) provided in the core operating limits report (COLR).

THERMAL POWER Where: P=

RATED THERMAL POWER K(Z) = the normalized F0 (Z) as a function of core height specified in the COLR.

APPLICABILITY: MODE 1.

ACTION:

With FQ(Z) exceeding its limit:

a. For RAOC operation with Specification 4.2.2.1.2.b not being satisfied or for base load operation with Specification 4.2.2.1.4.b not being satisfied:

(1) Reduce THERMAL POWER at least 1%. for each 1% FQ(Z) exceeds the limit within 15 minutes and similarly reduce the Power Range Neutron Flux-High Trip Setpoints within the next 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />; POWER OPERATION may proceed for up to a total of 72 hours3 days <br />0.429 weeks <br />0.0986 months <br />; subsequent POWER OPERATION may proceed provided the Overpower AT Trip setpoints have been reduced at least 1% for each 1% FQ(Z) exceeds the limit, and MILLSTONE - UNIT 3 3/4 2-5 Amendment No. yp, fP, ii, jXp, 0972 J79.217

POWER DISTRIBUTION LIMITS LIMITING CONDITION FOR OPERATION (Continued)

(2) Identify and correct the cause of the out-of-limit condition prior to increasing THERMAL POWER above the reduced limit required by item (1) above; THERMAL POWER may then be increased provided Fu(Z) is demonstrated through incore mapping to be within its limits.

b. For RAOC operation with Specification 4.2.2.1.2.c not being satisfied, one of the following actions shall be taken:

(1) Within 15 minutes, control the AFD to within new AFD limits which are determined by reducing the AFD limits specified in the CORE OPERATING LIMITS REPORT by at least 1% AFD for each percent FQ(Z) exceeds its limits. Within 8 hours0.333 days <br />0.0476 weeks <br />0.011 months <br />, reset the AFD alarm setpoints to these modified limits, or (2) Verify that the requirements of Specification 4.2.2.1.3 for base load operation are satisfied and enter base load operation.

Where it is necessary to calculate the percent that FQ(Z) exceeds the limits for item (1) above, it shall be calculated as the maximum percent over the core height (Z), consistent with Specification 4.2.2.1.2.f, that FQ(Z) exceeds its limit by the following expression:

lF(Z) x 1 lx 100 for P > O x K(Z) j Fom(Z)

FM0 (Z) ;X W(Z)

') 31 x 100 for P 0.

0 5

c. For base load operation with Specification 4.2.2.1.4.c not being satisfied, one of the following actions shall be taken:

(1) Place the core in an equilibrium condition where the limit in 4.2.2.1.4.c is satisfied, and remeasure FQM(Z), or MILLSTONE - UNIT 3 3/4 2-6 Amendment No. 99, 17?, 170 0607 1 . j .

POWER DISTRIBUTION LIMITS LIMITING CONDITION FOR OPERATION (ernt. nued)

(2) Reduce THERMAL POWER at least 1% for each 1% F0,(Z) exceeds the limit within 15 minutes and similarly reduce the Power Range Neutron Flux-High Trip Setpoints within the next 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />; POWER OPERATION may proceed for up to a total of 72 hours3 days <br />0.429 weeks <br />0.0986 months <br />; subsequent POWER OPERATION may proceed provided the Overpower AT Trip

-Setpoints have been reduced at least 1% for each 1% Fa(Z) exceeds its limit shall be calculated as the maximum percent over the core height (Z), consistent with Specification 4.2.2.1.4.f, by the following expression:

(( Fgo(Z) x W(Z) EL I 1 x 100 for P k APL SURVEILLANCE REQUIREMENTS 4.2.2.1.1 The provisions of Specification 4.0.4 are not applicable.

4.2.2.1.2 For RAOC operation, FQ(Z) shall be evaluated to determine if F0a(Z) is within its limit by:

a. Using the movable incore detectors to obtain a power distribution map at any THERMAL POWER greater than 5% of RATED THERMAL POWER.

b. Evaluate the computed heat flux hot channel factor by performing both of the following:

(1) Determine the computed heat flux hot channel Factor, FQM(Z) by increasing the measured FO(Z) component of the power distribution map by 3% to account for manufacturing tolerances and further increase the value by 5% to account for measurement uncertainties, and (2) Verify that F0 M(Z) satisfies the requirements of Specification 3.2.2.1 for all core plane regions, i.e. 0-100% inclusive.

MILLSTONE - UNIT 3 3/4 2-7 Amendment No. I?, fo. FF. 170 0607 Cats XNto, 4, j qq

POWER DISTRIBUTION LIMITS SURVEILLANCE REQUIREMENTS (Continued)

c. Satisfying the following relationship:

FM1~ ~F"TP Fm(Z) < F X K(Z) x K(Z) for P > 0.5 F RxP X K(Z) for P < 0.5 where Fm(Z) is the measured F0(Z) increased by the allowances for manufacturing tolerances and measurement uncertainty, FQTP is the F0 limit, K(Z) is the normalized FQ(Z) as a function of core height, P is the relative THERMAL POWER, and W(Z) is the cycle-dependent function that accounts for power distribution transients encountered during normal operation. FQTP, K(Z), and W(Z) are specified in the CORE OPERATING LIMITS REPORT as per Specification 6.9.1.6.

d. Measuring flg(Z) according to the following schedule:

(1) Upon achieving equilibrium conditions after exceeding by 10% or more of RATED THERMAL POWER, the THERMAL POWER at which F,(Z) was last determined,* or (2) At least once per 31 Effective Full Power Days, whichever occurs first.

e. With the maximum value of F" (Z)

K(Z) over the core height (Z) increasing since the previous determination of Fm(Z), either of the following actions shall be taken:

(1) Increase FQM(Z) by an appropriate factor specified in the COLR and verify that this value satisfies the relationship in Specification 4.2.2.1.2.c, or

• During power escalation at the beginning of each cycle, power level may be increased until a power level for extended operation has been achieved and power distribution map outlined.

MILLSTONE - UNIT 3 3/4 2-8 Amendment No. by, f0, ly, X??, 170 oeo7

POWER DJSTRIBUTION LIMITS SURVEILLANCE REQUIREMENTS (Continued)

(2) Fm(Z) shall be measured at least once per 7 Effective Full Power Days until two successive maps indicate that the maximum value of Fa'(Z)

K(Z) over the core height (Z) is not increasing.

f. The limits specified in Specifications 4.2.2.1.2c and 4.2.2.1.2e above are not applicable in the following core plane regions:

(1) Lower core region from 0% to 15%, inclusive.

(2) Upper core region from 85% to 100%, inclusive.

4.2.2.1.3 Base load operation is permitted at powers above APLNE if the following conditions are satisfied:

a. Prior to entering base load operation, maintain THERMAL POWER above APLND and less than or equal to that allowed by Specifica-tion 4.2.2.1.2 for at least the previous 24 hours1 days <br />0.143 weeks <br />0.0329 months <br />. Maintain base load operation surveillance (AFD within the target band limit about the target flux difference of Specification 3.2.1.1) during this time period. Base load operation isthen permitted providing THERMAL POWER is maintained between APLOD and APLL or between APLND and 100%

(whichever is most limiting) and F0 surveillance is maintained pursuant to Specification 4.2.2.1.4. APLL is defined as the minimum value of:

APL&= Fi xK(Z) x100%

FA'(Z) X Yl(Z)sgL over the core height (Z) where: FM(Z) is the measured FQ(Z) increased by the allowances for manufacturing tolerances and mea-surement uncertainty. The F. limit is F:7. W(Z)B is the cycle-dependent function that accounts for limited power distribution transient encountered during base load operation. Fa 1,K(Z), and W(Z)9. are specified in the COLR as per Specification 6.9.1.6.

MILLSTONE - UNIT 3 3/4 2-9 Amendment Fo, 99

POWER DISTRIBUTION LIMITS

,SURVEILLANCE REQUIREMENTS (Continued)

b. During base load operation, if the THERMAL POWER is decreased below APLND then the conditions of 4.2.2.1.3.a shall be satisfied before reentering base load operation.

4.2.2.1.4 During base load operation F.(7) shall be evaluated to determine if FQ(Z) is within its limit by:

a. Using the movable incore detectors to obtain a power distribution map at any THERMAL POWER above APLND.

b. Evaluate the computed heat flux hot channel factor by performing both of the following:

(1) Determine the computed heat flux hot channel factor, F0 M(Z), by increasing the measured FQM(Z) component of the power distribution map by 3% to account for manufacturing tolerances and further increase the value by 5% to account for measurement uncertainties, and (2) Verify that F0 M(Z) satisfies the requirements of Specification 3.2.2.1 for all core plane regions, i.e., 0 - 100% inclusive.

c. Satisfying the following relationship:

FR0"TP x K(Z)

F (Z)~

• Q (Z for P > APL NO where: Fm(Z) is the measured FQ(Z) increased by the allowances for manufacturing tolerances and measurement uncertainty, F.TP is the F. limit, K(Z) is the normalized F,(Z) as a function of core height, P is the relative THERMAL POWER, and W(Z)BL is the cycle-dependent function that accounts for limited power distribution transients encountered during base load operation.

FRTP, K(Z), and W(Z)BL are specified in the COLR as per Specification 6.9.1.6.

d. Measuring Fm(Z) in conjunction with target flux difference determi-nation according to the following schedule:

(1) Prior to entering base load operation after satisfying Sec-tion 4.2.2.1.3 unless a full core flux map has been taken in the previous 31 EFPD with the relative thermal power having been maintained above APLND for the 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> prior to mapping, and (2) At least once per 31 Effective Full Power Days.

MILLSTONE - UNIT 3 3/4 2-10 Amendment No. F9, fo, l, 17 0 0607

POWER DISTRIBUTION LIMITS SURVEILLANCE REQUIREMENTS (Continued)

e. With the maximum value of Fo (Z)

K(Z) over the core height (Z) increasing since the previous determination of Fm(Z), either of the following actions shall be taken:

(1) Increase FQM(Z) by appropriate factor specified in the COLR and verify that this value satisfies the relationship in Specification 4.2.2.1.4.c, or (2) FQ (Z) shall be measured at least once per 7 Effective Full Power Days until 2 successive maps indicate that the maximum value of F., (Z)

K(Z) over the core height (Z) is not increasing.

f. The limits specified in 4.2.2.1.4.c and 4.2.2.1.4.e are not applicable in the following core plane regions:

(1) Lower core region 0% to 15%, inclusive.

(2) Upper core region 85% to 100%, inclusive.

4.2.2.1.5 When FU(Z) is measured for reasons other than meeting the require-ments of Specifications 4.2.2.1.2 or 4.2.2.1.4, an overall measured F0 (Z) shall be obtained from a power distribution map and increased by 3% to account for manufacturing tolerances and further increased by 5% to account for measurement uncertainty.

3/4 2-11 Amendment No. F9, PR, FF, JZ0, 170 0607 v - ,. ..

This page intentionally left blank.

MILLSTONE

-1.e

- UNIT 3 3/4 2-12 Anendment No. y?, fo, ii, 7Z,217

This page intentionally left blank.

MILLSTONE - UNIT 3 3/4 2-13 Amendment No. FY. PIP, 217 0973

This page intentionally left blank.

MILLSTONE - UNIT 3 3/4 2-14 Amendment No. Of, f9, PY, 217

This page intentionally left blank.

MILLSTONE - UNIT 3 3/4 2-15 Anendment No. 77, d, P, a, fl0, 217 0973

This page intentionally left blank.

MILLSTONE - UNIT 3 3/4 2-16 Amendment No. 77, pp, F9, g?, 217 0973

This page intentionally left blank.

MILLSTONE - UNIT 3 3/4 2-17 Amendment No. i7,Yp, fg, ii, 0973 JZ, 217

This page intentionally left blank.

MILLSTONE - UNIT 3 3/4 2-18 Amendment No. 77, 0, YR, Y7, 217 0973

POWER DISTRIBUTION LIMITS 3/4.2.3 RCS FLOW RATE AND NUCLEAR ENTHALPY RISE HOT CHANNEL FACTOR LIMITING CONDITION FOR OPERATION 3.2.3.1 The indicated Reactor Coolant System (RCS) total flow rate and FNH shall be maintained as follows:

a. RCS total flow rate > 371,920 gpm, and

b. FaH < FRT [1.0 + PFAH (1.0 - P)]

Where:

1) P THERMAL POWER RATED THERMAL POWER

2) FH = Measured values of Fa'H obtained by using the movable incore detectors to obtain .a power distribution map. The measured value of FL should be used since Specification 3.2.3.1b.

takes into consideration a measurement uncertainty of 4% for incore measurement,

3) F RTP = The FA' limit at RATED THERMAL POWER in the CORE OPERATING LIMITS REPORT (COLR),

4) PFAH - The power factor multiplier for FAN provided in the COLR, and

5) The measured value of RCS total flow rate shall be used since uncertainties of 2.4% for flow measurement have been included in Specification 3.2.3.1a.

APPLICABILITY: MODE 1.

ACTION:

With the RCS total flow rate or FAH outside the region of acceptable operation:

a. Within 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> either:

1. Restore the RCS total flow rate and F"H to within the above limits, or

2. Reduce THERMAL POWER to less than 50% of RATED THERMAL POWER and reduce the Power Range Neutron Flux - High Trip Setpoint to less than or equal to 55% of RATED THERMAL POWER within the next 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />.

MILLSTONE - UNIT 3 3/4 2-19 Amendment No. ZZ, 0. F, JW', 217 0973

POWER DISTRIBUTION LIMITS LIMITING CONDITION FOR OPERATION ACTION (Continued)

b. Within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> of initially being outside the above limits, verify through incore flux mapping and RCS total flow rate that FL and RCS total flow rate are restored to within the above limits, or reduce THERMAL POWER to less than 5% of RATED THERMAL POWER within the next 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br />.

c. Identify and correct the cause of the out-of-limit condition prior to increasing THERMAL POWER above the reduced THERMAL POWER limit required by ACTION a.2. and or b., above; subsequent POWER OPERATION may proceed provided that V and indicated RCS total flow rate are demonstrated, through incore flux mapping and RCS total flow rate comparison, to be within the region of acceptable operation prior to exceeding the following THERMAL POWER levels:

1. A nominal 50% of RATED THERMAL POWER,

2. A nominal 75% of RATED THERMAL POWER, and

3. Within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> of attaining greater than or equal to 95% of RATED THERMAL POWER.

SURVEILLANCE REQUIREMENTS 4.2.3.1.1 The provisions of Specification 4.0.4 are not applicable.

4.2.3.1.2 RCS total flow rate and F'o" shall be determined to be within the acceptable range:

a. Prior to operation above 75% of RATED THERMAL POWER after each fuel loading, and

b. At least once per 31 Effective Full Power Days.

4.2.3.1.3 The indicated RCS total flow rate shall be verified to be within the acceptable range at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> when the most recently obtained value of Fo., obtained per Specification 4.2.3.1.2, is assumed to exist.

4.2.3.1.4 The RCS total flow rate indicators shall be subjected to a CHANNEL CALIBRATION at least once per 18 months. The measurement instrumentation shall be calibrated within 7 days prior to the performance of the calorimetric flow measurement.

MILLSTONE - UNIT 3 3/4 2-20 Amendment No. Ip, 79,100 0234 -, . !;

• 0;-1' ams p i~J

POWER DISTRIBUTION LIMITS SURVEILLANCE REOUIREMENTS (Continued) 4.2.3.1.5 The RCS total flow rate shall be determined by precision heat balance measurement at least once per 18 months. Within 7 days prior to performing the precision heat balance, the Instrumentation used for determination of steam pressure, feedwater pressure, feedwater temperature, and feedwater venturi AP in the calorimetric calculations shall be calibrated.

4.2.3.1.6 If the feedwater venturis are not inspected at least once per 18 months, an additional 0.1% will be added to the total RCS flow measurement uncertainty.

MILLSTONE - UNIT 3 Coll 3/4 2-21 Amendment No. g7,60

.. . :. . 'j 1i I

This page intentionally left blank.

MILLSTONE - UNIT 3 3/4 2-22 Amendment No. 17, Fp, A, 217 0974

This page intentionally left blank.

MILLSTONE - UNIT 3 3/4 2-23 Amendment No. 77, PR, 7i, 1Y0. 217 0974

POWER DISTRIBUTION LIMITS 3/4.2.4 QUADRANT POWER TILT RATIO LIMITING CONDITION FOR OPERATION 3.2.4 The QUADRANT POWER TILT RATIO shall not exceed 1.02.

AEPPICABILIT: MODE 1, above 50% of RATED THERMAL POWER*.

ACTION:

a. With the QUADRANT POWER TILT RATIO determined to exceed 1.02 but less than or equal to 1.09:

1. Calculate the QUADRANT POWER TILT RATIO at least once per hour until either:

a) The QUADRANT POWER TILT RATIO is reduced to within its limit, or b) THERMAL POWER is reduced to less than 50% of RATED THERMAL POWER.

2. Within 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> either:

a) Reduce the QUADRANT POWER TILT RATIO to within its limit, or b) Reduce THERMAL POWER at least 3% from RATED THERMAL POWER for each 1% of indicated QUADRANT POWER TILT RATIO in excess of I and similarly reduce the Power Range Neutron Flux-High Trip Setpoints within the next 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />.

3. Verify that the QUADRANT POWER TILT RATIO is within its limit.

within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> after exceeding the limit or reduce THERMAL POWER to less than 50% of RATED THERMAL POWER Within the next 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> and reduce the Power Range Neutron Flux-High Trip Setpoints to less than or equal to 55% of RATED THERMAL POWER within the next 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />; and

4. Identify and correct the cause of the out-of-limit condition prior to increasing THERMAL POWER; subsequent POWER OPERATION above 50% of RATED THERMAL POWER may proceed provided that the QUADRANT POWER TILT RATIO is verified within its limit at least once per hour for 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> or until verified acceptable at 95%

or greater RATED THERMAL POWER.

• See Special Test Exceptions Specification 3.10.2.

MILLSTONE - UNIT 3 3/4 2-24 Amendment No. 60 l 08Q1 1 "'S : -

POWER DISTRIBUTION LIMITS LIMITING CONQITION FOR OPERATION ACTION (Continued)

b. With the QUADRANT POWER TILT RATIO determined to exceed 1.09 due to misalignment of either a shutdown or control rod:

1. Calculate the QUADRANT POWER TILT RATIO at least once per hour until either:

a) The QUADRANT POWER TILT RATIO is reduced to within its limit, or b) THERMAL POWER is reduced to less than 50% of RATED THERMAL POWER.

2. Reduce THERMAL POWER at least 3% from RATED THERMAL POWER for each 1% of indicated QUADRANT POWER TILT RATIO in excess of 1, within 30 minutes;

3. Verify that the QUADRANT POWER TILT RATIO is within its limit within 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> after exceeding the limit or reduce THERMAL POWER to less than 50% of RATED THERMAL POWER within the next 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> and reduce the Power Range Neutron Flux-High Trip Setpoints to less than or equal to 55% of RATED THERMAL POWER within the next 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />; and

4. Identify and correct the cause of the out-of-limit condition prior to increasing THERMAL POWER; subsequent POWER OPERATION above 50% of RATED THERMAL POWER may proceed provided that the QUADRANT POWER TILT RATIO is verified within its limit at least once per hour for 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> or until verified acceptable at 95%

or greater RATED THERMAL POWER.

c. With the QUADRANT POWER TILT RATIO determined to exceed 1.09 due to causes other than the misalignment of either a shutdown or control rod:

1. Calculate the QUADRANT POWER TILT RATIO at least once per hour until either:

a) The QUADRANT POWER TILT RATIO is reduced to within its limit, or b) THERMAL POWER is reduced to less than 50% of RATED THERMAL POWER.

MILLSTONE - UNIT 3 3/4 2-25 Amendment No. 60 Coll  :

POWER DISTRIBUTION LIMITS LIMITING CONDITION FOR OPERATION ACTION (Contjnued)

2. Reduce THERMAL POWER to less than 50% of RATED THERMAL POWER within 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> and reduce the Power Range Neutron Flux-High Trip Setpoints to less than or equal to 55% of RATED THERMAL POWER within the next 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />; and

3. Identify and correct the cause of the out-of-limit condition prior to increasing THERMAL POWER; subsequent POWER OPERATION above 50% of RATED THERMAL POWER may proceed provided that the QUADRANT POWER TILT RATIO is verified within its limit at least once per hour for 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> or until verified at 95% or greater RATED THERMAL POWER.

SURVEILLANCE REQUIREMENTS 4.2.4.1 The QUADRANT POWER TILT RATIO shall be determined to be within the limit above 50% of RATED THERMAL POWER by:

a. Calculating the ratio at least once per 7 days when the alarm is OPERABLE, and

b. Calculating the ratio at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> during steady-state operation when the alarm is inoperable.

4.2.4.2 The QUADRANT POWER TILT RATIO shall be determined to be within the limit when above 75% of RATED THERMAL POWER with one Power Range channel Inoperable by using the movable incore detectors to confirm that the normalized symmetric power distribution, obtained from two sets of four symmetric thimble locations or full-core flux map, is consistent with the indicated QUADRANT POWER TILT RATIO at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />.

0 MILLSTONE 0011

- UNIT 3 3/4 2-26 Amendment No. A7,60

"..'. I .. I JJi I

POWER DISTRIBUTION LIMITS 3/4.2.5 DNB PARAMETERS LIMITING CONDITION FOR OPERATION 3.2.5 The following DNB-related parameters shall be maintained within the limits specified in the CORE OPERATING LIMITS REPORT (COLR):

a. Reactor Coolant System Tavg, and

b. Pressurizer Pressure.

APPLICABILITY: MODE 1.

ACTION:

With any of the above parameters exceeding its limit, restore the parameter to within its limit within 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> or reduce THERMAL POWER to less than 5% of RATED THERMAL POWER within the next 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />.

SURVEILLANCE REQUIREMENTS 4.2.5 Each of the above DNB-related parameters shall be verified to be within the limits specified in the COLR at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />. l MILLSTONE - UNIT 3 3/4 2-27 Amendment No. -,6C, 218

THIS PAGE INTENTIONALLY LEFT BLANK MILLSTONE - UNIT 3 3/4 2-28 Amendment No. 4-2, 6, 21, 218

3/4.3 INSTRUMENTATION 3/4.3.1 REACTOR TRIP SYSTEM INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.1 As a minimum, the Reactor Trip System instrumentation channels and interlocks of Table 3.3-1 shall be OPERABLE.

APPLICABILITY: As shown in Table 3.3-1.

ACTION:

As shown in Table 3.3-1.

SURVEILLANCE REQUIREMENTS 4.3.1.1 Each Reactor Trip System instrumentation channel and interlock and the automatic trip logic shall be demonstrated OPERABLE by the performance of the Reactor Trip System Instrumentation Surveillance Requirements specified in Table 4.3-1.

4.3.1.2 The REACTOR TRIP SYSTEM RESPONSE TIME of each Reactor trip function shall be verified to be within its limit at least once per 18 months.

Neutron detectors and speed sensors are exempt from response time verification.

Each verification shall include at least one train such that both trains are verified at least once per 36 months and one channel (to include input relays to both trains) per function such that all channels are verified at least once every N times 18 months where N is the total number of redundant channels in a specific Reactor trip function as shown in the HTotal No. of Channels column of Table 3.3-1.

MILLSTONE - UNIT 3 3/4 3-1 Amendment No. Y, 7s, PA. IPP , 187 0720

TABLE 3s.3-1 0 =

REACTOR TRIP SYSTEM INSTRUMENTATION I-MINIMUM 0

M TOTAL NO. CHANNELS CHANNELS APPLICABLE FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION C

1. Manual Reactor Trip 2 1 2 1, 2 1 ID 2 1 2 3*, 4*, 5*

11

2. Power Range, Neutron Flux

-I a. High Setpoint 4 2 3 1, 2 2

b. Low Setpoint 4 2 3 1###, 2 2

3. Power Range, Neutron Flux 4 2 3 1, 2 2 High Positive Rate red

4. Deleted

5. Intermediate Range, Neutron Flux 2 1 2 1###, 2 3

6. Source Range, Neutron Flux

a. Startup 2 1 2 2## 4

b. Shutdown 2 1 2 3*, 4*, 5* 11

7. Overtemperature AT 4 2 3 1, 2 6 I

8. Overpower AT 4 2 3 1, 2 6 I

9. Pressurizer Pressure--Low 4 2 3 1** 6 (1)

- 10. Pressurizer Pressure--High 4 2 3 1, 2 6 (1)

-4 11. Pressurizer Water Level--High 3 2 2 1** 6

TABLE 3.3-1 (Continued)

CO REXXCTOR TRIP SYSTEM INSTRUMENTATION MINIMUM TOTAL NO. CHANNELS CHANNELS APPLICABLE g FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION

12. Reactor Coolant Flow--Low

a. Single Loop (Above P-8) 3/loop 2/loop 2/loop 6

b. Two Loops (Above P-7 and 1 3/loop 2/loop in two 2/loop 6 below P-8) operating loops

13. Steam Generator Water 4/stm. gen. 2/stm. gen. 3/stm. gen. 1,2 6 (1)

Level--Low-Low

14. Low Shaft Speed--Reactor 4-1/pump 2 3 1** 6 wj Coolant Pumps

15. Turbine Trip

a. Low Fluid Oil Pressure 3 2 2 1*** 12

b. Turbine Stop Valve Closure 4 4 4 1*** 6

16. Deleted

17. Reactor Trip System Interlocks

a. Intermediate Range 2 1 2 8 Neutron Flux, P-6

b. Low Power Reactor Trips Block, P-7 z Power Range Neutron Flux, 4 2 3 I 8

• P-1O Input I or Turbine Impulse Chamber 2 I 2 1 8 Pressure, P-13 Input I

IN, 0o

o@3 TABLE 3.3-1 (Continued)

REACTOR TRIP SYSTEM INSTRUMENTATION rat MINIMUM TOTAL NO. CHANNELS CHANNELS APPLICABLE FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION

17. Reactor Trip System Interlocks (Continued)

c. Power Range Neutron Flux, P-8 4 2 3 1 8

d. Power Range Neutron 4 2 3 1 8 Flux, P-9

e. Power Range Neutron Flux, P-10 4 2 3 1,2 8

" 18. Reactor Trip Breakers(2 ) 2 1 2 1, 2 10, 13 2 1 2 3*, 4*, 5* 11

19. Automatic Trip and Interlock 2 1 2 1, 2 13A Logic 2 1 2 3*, 4*, 5* 11 i 20. DELETED I 3 21. DELETED t13 a

t*1

'-a

TABLE 3.3-1 (Continued)

TABLE NOTATIONS

• When the Reactor Trip System breakers are in the closed position and the Control Rod Drive System is capable of rod withdrawal.

• • Above the P-7 (At Power) Setpoint.

• • • Above the P-9 (Reactor Trip/Turbine Trip Interlock) Setpoint.

1. 1. Below the P-6 (Intermediate Range Neutron Flux Interlock) Setpoint.

1. 1. 1. Below the P-10 (Low Setpoint Power Range Neutron Flux Interlock) Setpoint.

(1) The applicable MODES and ACTION statements for these channels noted in Table 3.3-3 are more restrictive and, therefore,. applicable.

(2) Including any reactor trip bypass breakers that are racked in and closed for bypassing a reactor trip breaker.

ACTION STATEMENTS ACTION 1 - With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 48 hours2 days <br />0.286 weeks <br />0.0658 months <br /> or be in HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />.

ACTION 2 - With the number of OPERABLE channels one less than the Total Number of Channels, STARTUP and/or POWER OPERATION may proceed provided the following conditions are satisfied:

a. The inoperable channel is placed in the tripped condition within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />,

b. The Minimum Channels OPERABLE requirement is met; however, the inoperable channel may be bypassed for up to 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> for surveillance testing of other channels per Specification 4.3.1.1, and

c. Either, THERMAL POWER is restricted to less than or equal to 75% of RATED THERMAL POWER and the Power Range Neutron I Flux Trip Setpoint is reduced to less than or equal to 85%

of RATED THERMAL POWER within 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />; or, the QUADRANT I POWER TILT RATIO is monitored at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> per Specification 4.2.4.2.

MILLSTONE - UNIT 3 3/4 3-5 Amendment No. U7, M, PI, 0976 7f*. 217

TABLE 3.3-1 (Continued)

ACTION STATEMENTS (Continued)

ACTION 3 - With the number of channels OPERABLE one less than the Minimum Channels OPERABLE requirement and with the THERMAL POWER level:

a. Below the P-6 (Intermediate Range Neutron Flux Interlock)

Setpoint, restore the inoperable channel to OPERABLE status prior to increasing THERMAL POWER above the P-6 Setpoint, and

b. Above the P-6 (Intermediate Range Neutron Flux Interlock)

Setpoint but below 10% of RATED THERMAL POWER, restore the inoperable channel to-OPERABLE status prior to increasing THERMAL POWER above 10% of RATED THERMAL POWER.

ACTION 4 - With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement, suspend all operations involving positive reactivity changes.

ACTION 5 - (Not used) I ACTION 6 - With the number of OPERABLE channels one less than the Total Number of Channels, STARTUP and/or POWER OPERATION may proceed provided the following conditions are satisfied:

a. The inoperable channel is placed in the tripped condition within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />, and

b. The Minimum Channels OPERABLE requirement is met; however, the inoperable channel may be bypassed for up to 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> for surveillance testing of other channels per Specification 4.3.1.1.

ACTION 7 - (Not used)

ACTION 8 - With less than the Minimum Number of Channels OPERABLE, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> determine by observation of the associated permissive annunciator window(s) that the interlock is in its required state for the existing plant condition, or apply Specification 3.0.3.

ILLSTONE - UNIT 3 3/4 3-6 Amendment No. F7, fF, JfX, 164 0492

TABLE 3.3-1 (Continued)

ACTION STATEMENTS (Continued)

ACTION 9 - (Not used) I ACTION 10 - With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement, be in at least HOT STANDBY within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />; however, one channel may be bypassed for up to 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> for surveillance testing per Specification 4.3.1.1, provided the other channel is OPERABLE.

ACTION 11 - With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 48 hours2 days <br />0.286 weeks <br />0.0658 months <br /> or open the Reactor Trip System breakers within the next hour.

ACTION 12 - With the number of OPERABLE channels one less than the Total Number of Channels, STARTUP and/or POWER OPERATION may proceed provided the following conditions are satisfied:

a. The inoperable channel is placed in the tripped condition within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />, and

b. When the Minimum Channels OPERABLE requirement is met, the inoperable channel may be bypassed for up to 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> for surveillance testing of the Turbine Control Valves.

ACTION 13 - With one of the diverse trip features (undervoltage or shunt trip attachments) inoperable, restore it to OPERABLE status within 48 hours2 days <br />0.286 weeks <br />0.0658 months <br /> or declare the breaker inoperable and apply ACTION 10. The breaker shall not be bypassed while one of the diverse trip features is inoperable except for the time required for performing maintenance to restore the breaker to OPERABLE status.

ACTION 13A - With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement, restore the inoperable Channel to OPERABLE status within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />; however, one channel may be bypassed for up to 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> for surveillance testing per Specification 4.3.1.1, provided the other channel is operable.

MILLSTONE - UNIT 3 3/4 3-7 Amendment No. 70, 89, 005G i.

This page is intentionally left blank MILLSTONE - UNIT 3 3/4 3-8 Amendment No. IZ, 09' 91 esze

This page is intentionally left blank MILLSTONE - UNIT 3 3/4 3-9 Amendment Ho. i, 91 Dole

TABLE 4.3-1 cj1 REACTOR TRIP SYSTEM INSTRUMENTATION SURVEILLANCE REOUIREMENTS 0 TRIP z

M~ ANALOG ACTUATING MODES FOR CHANNEL DEVICE WHICH CHANNEL CHANNEL OPERATIONAL OPERATIONAL ACTUATION SURVEILLANCE i FUNCTIONAL UNIT CHECK CALIBRATION TEST TEST LOGIC TEST IS REOUIRED Wj

1. Manual Reactor Trip N.A. N.A. N.A. R(14) N.A. 1, 2,3*, 4*, 5*

2. Power Range, Neutron Flux

a. High Setpoint S D(2, 4), Q N.A. N.A. 1,2 M(3, 4),

Q(4, 6),

0 R(4, 5)

b. Low Setpoint S R(4, 5) S/U(1) N.A. N.A. 1***, 2

3. Power Range, Neutron Flux, N.A. R(4, 5) Q N.A. N.A. 1,2 High Positive Rate

4. Deleted 3

5. Intermediate Range S R(4, 5) S/U(1) N.A. N.A. 1***, 2

6. Source Range, Neutron Flux S R(4, 5) S/U(1), N.A. N.A. 2**, 3*, 4*, 5* I a

0 Q(9)

Z 7. Overtemperature AT S R Q N.A. N.A. 1,2

8. Overpower AT S R Q N.A. N.A. 1,2

9. Pressurizer Pressure-Low S R Q(18) N.A. N.A. 1**t***

I

10. Pressurizer Pressure--High S R Q(18) N.A. N.A. 1,2

11. Pressurizer Water Level--High S R Q N.A. N.A. 1*****

I

12. Reactor Coolant Flow--Low S R Q N.A. N.A. I r11 N)

o=

U, 20 TABLE 4.3-1 (Continued)

CO Z: REACTOR TRIP SYSTEM INSTRUMENTATION SURVEILLANCE REOUIREMENTS

-I TRIP ANALOG ACTUATING MODES FOR

'*5 CHANNEL DEVICE WHICH CHANNEL CHANNEL OPERATIONAL OPERATIONAL ACTUATION SURVEILLANCE FUNCTIONAL UNIT CHECK CALIBMATION TEST LOGIC TEST IS REQUIRED

13. Steam Generator Water Level-- S R Q(18) N.A. N.A. 1, 2 Low-Low

14. Low Shaft Speed - Reactor N.A. R(13) Q N.A. N.A. I Coolant Pumps

15. Turbine Trip

a. Low Fluid Oil Pressure N.A. R N.A. S/U(1, 10)****N.A. 1

b. Turbine Stop Valve N.A. R N.A. S/U(1, 10)****N.A. 1 W Closure

16. Deleted W

'.I

17. Reactor Trip System Interlocks

a. Intermediate Range Neutron Flux, P-6 N.A. R(4) R N.A. N.A. 2**

b. Low Power Reactor Trips Block, P-7 N.A. R(4) R N.A. N.A.

c. Power Range Neutron Flux, P-8 N.A. R(4) R N.A. N.A. 1

d. Power Range Neutron Flux, P-9 N.A. R(4) R N.A. N.A. 1

e. Power Range 1, Neutron Flux P-10 N.A. R(4) R N.A. N.A.

f. Turbine Impulse Chamber Pressure, P-13 N.A. R R N.A. N.A. 1 9z 0!

9D 0:

TABLE 4.3-1 (Continued)

'-I (A REACTOR TRIP SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS

-4 0

TRIP ANALOG ACTUATING MODES FOR CHANNEL DEVICE WHICH 1-g CHANNEL CHANNEL OPERATIONAL OPERATIONAL ACTUATION SURVEILLANCE (A)

FUNCTIONAL UNIT CHECK CALIBRATION TEST TEST LOGIC TEST IS REQUIRED

18. Reactor Trip Breaker N.A. N.A. N.A. M(7, 11) N.A. 1 2 3*

4, i*

19. Automatic Trip and N.A. N.A. N.A. N.A. M(7) 1*Y26* 3*.

Interlock Logic 4~

20. DELETED I

21. Reactor Trip Bypass N.A. N.A. N.A. M(7 15) N.A. 1 2 3*,

Breaker R 16) )*

4*,

22. DELETED

-t (A)

D a

(A) a Ct, I" 0

• 'M w N0I

TABLE 4.3-1 (Continued)

TABLE NOTATIONS

• When the Reactor Trip System breakers are closed and the Control Rod Drive System is capable of rod withdrawal.

• • Below P-6 (Intermediate Range Neutron Flux Interlock) Setpoint.

• • • Below P-IO (Low Setpoint Power Range Neutron Flux Interlock) Setpoint.

• • • • Above the P-9 (Reactor Trip/Turbine Interlock) Setpoint.

• • • • • Above the P-7 (At Power) Setpoint (1) If not performed in previous 31 days.

(2) Comparison of calorimetric to excore power indication above 15% of RATED THERMAL POWER. Adjust excore channel gains consistent with calorimetric power if absolute difference is greater than 2%. The provisions of Specification 4.0.4 are not applicable to entry into MODE 2 or 1.

(3) Single point comparison of incore to excore AXIAL FLUX DIFFERENCE above 15% of RATED THERMAL POWER. Recalibrate if the absolute difference is greater than or equal to 3%. The provisions of Specification 4.0.4 are not applicable for entry into MODE 2 or 1.

(4) Neutron detectors may be excluded from CHANNEL CALIBRATION.

(5) Detector plateau curves shall be obtained, and evaluated and compared to manufacturer's data. For the Source Range, Intermediate Range and Power Range Neutron Flux channels the provisions of Specification 4.0.4 are not applicable for entry into MODE 2 or 1.

(6) Incore - Excore Calibration, above 75% of RATED THERMAL POWER. The provisions of Specification 4.0.4 are not applicable for entry into MODE 2 or 1.

(7) Each train shall be tested at least every 62 days on a STAGGERED TEST BASIS.

(8) (Not used)

(9) Quarterly surveillance in MODES 3*, 4*, and 5* shall also include verification that permissives P-6 and P-l 0 are in their required state for existing plant conditions by observation of the permissive annunciator window.

MILLSTONE - UNIT 3 3/4 3-13 Amendment No. 60, 0, 409, 220

TABLE 4.3-1 (Continued)

TABLE NOTATIONS (Continued)

(10) Setpoint verification is not applicable.

(11) The TRIP ACTUATING DEVICE OPERATIONAL TEST shall independently verify the OPERABILITY of the undervoltage and shunt trip attachments of the Reactor Trip Breakers.

(12) (not used)

(13) Reactor Coolant Pump Shaft Speed Sensor may be excluded from CHANNEL CALIBRATION.

(14) The TRIP ACTUATING DEVICE OPERATIONAL TEST shall independently verify the OPERABILITY of the undervoltage and shunt trip circuits for the Manual Reactor Trip Function. The test shall also verify the OPERABILITY of the Bypass Breaker trip circuit(s).

(15) Local manual shunt trip prior to placing breaker in service.

(16) Automatic undervoltage trip.

(17) (not used).

(18) The surveillance frequency and/or MODES specified for these channels in Table 4.3-2 should be reviewed for applicability.

I MILLSTONE - UNIT 3 3/4 3-14 Amendment No. 7J, FPI 7P, 7F1 0484 IPP, 164

INSTRUMENTATION 3/4.3.2 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.2 The Engineered Safety Features Actuation System (ESFAS) instrumentation channels and interlocks shown in Table 3.3-3 shall be OPERABLE with their Trip Setpoints set consistent with the values shown in the Nominal Trip Setpoint I column of Table 3.3-4.

APPLICABILITY: As shown in Table 3.3-3.

a. With an ESFAS Instrumentation Channel or Interlock Channel Nominal Trip Setpoint inconsistent with the value shown in the Nominal Trip Setpoint column of Table 3.3-4, adjust the Setpoint consistent with the Nominal Trip Setpoint value.

b. With an ESFAS Instrumentation Channel or Interlock Channel found to be inoperable, declare the channel inoperable and apply the applicable ACTION statement requirements of Table 3.3-3 until the channel is restored to OPERABLE status.

1nlmen ; o. P A:,'e )

MILLSTONE - UNIT 3 3/4 3-15 Amendment No. Y;9159 0552

INSTRUMENTATION SURVEILLANCE REQUIREMENTS 4.3.2.1 Each ESFAS instrumentation channel and interlock and the automatic actuation logic and relays shall be demonstrated OPERABLE by performance of the ESFAS Instrumentation Surveillance Requirements specified in Table 4.3-2.

4.3.2.2 The ENGINEERED SAFETY FEATURES RESPONSE TIME* of each ESFAS function shall be verified to be within the limit at least once per 18 months.

Each verification shall include at least one train such that both trains are verified at least once per 36 months and one channel (to include input relays to both trains) per function such that all channels are verified at least once per N times 18 months where N is the total number of redundant channels in a specific ESFAS function as shown in the 'Total No. of Channels' column of Table 3.3-3.

• The provisions of Specification 4.0.4 are not applicable for response time verification of steam line isolation for entry into MODE 4 and MODE 3 and I turbine driven auxiliary feedwater pump for entry into MODE 3.

MILLSTONE - UNIT 3 3/4 3-16 Amendment No. fA, 77, Ff, 7p , 187 0721

TABLE 3.3-3 a0 Z

'- r, on ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION

-4 em CA MINIMUM z TOTAL NO. CHANNELS CHANNELS APPLICABLE FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION

-4 1. Safety Injection (Reactor La)

Trip, Feedwater Isolation, Control Building Isolation (Manual Initiation Only),

Start Diesel Generators, and Service Water).

a. Manual Initiation 2 1 2 1, 2, 3, 4 19

b. Automatic Actuation 2 1 2 1, 2, 3, 4 14 Logic and Actuation 4*

Relays

.- A c. Containment 3 2 2 1, 2, 3 20 Pressure--High-I

d. Pressurizer 4 2 3 I, 2, 3# 20 Pressure--Low 0.

ID e. Steam Line Pressure--

Low 3/steam line in each operating loop 2/steam line in any operating loop 2/steam line in each operating loop I, 2, 3# 20 i.

2. Containment Spray (CDA)

-I 0

a. Manual Initiation 2 1 with 2 1, 2, 3, 4 19 2 coincident switches

TABLLI3.3-3 (Continued)

ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENtATION X-trl MINIMUM 1-4 TOTAL NO. CHANNELS CHANNELS APPLICABLE FENUMNAL UNIT OF CHANNELS IO TRIP OPERABLE IMOES ACTION

'I 2. Containment Spray (CDA) (Continued)

Ei

b. Automatic Actuation 2 I 2 I, 2, 3, 4 14 Logic and Actuation Relays 3.

c. Containment Pressure--

High-3 Containment Isolation 4 2 . 3 1, 2, 3, 4 17 I

I, I") a. Phase 'A' Isolation

1) Manual Initiation 2 I 2 I, 2,3, 4 19

2) Automatic Actuation 2 I 2 1, 2,3, 4 14 Logic and Actuation Relays

3) Safety Injection See Item 1. above for all Safety Injection initiating functions and requirements.

3 5n (D

0. b. Phase 0B0 Isolation

1) Manual Initiation 2 1 with 2 1,2, 3, 4 19 0 2 coincident C.

switches CD

2) Automatic Actuation 2 I 2 1,2,3, 4 14 Logic and Actuation Relays

TABLE 3.3-3 (Continued)

ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION 0

MINIMUM TOTAL NO. CHANNELS CHANNELS APPLICABLE FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION

3. Containment Isolation (Continued)

3. Containment 4 2 3 1,2,3,4 17 Pressure-High-3

c. DELETED I

4. Steam Line Isolation AD0 a. Manual Initiation

1. Individual I/steam line I/steam line 1/operating 1,2,3,4 24 steam line

2. System 2 I 2 1,2,3,4 23

b. Automatic Actuation 2 I 2 1,2,3,4 22 Logic and Actuation Relays B

(D 0 c. Containment 3 2 2 1,2,3,4 20 Pressure--

z 3 High-2 To d. Steam Line Pressure-- 3/steam line in 2/steam line in 2/steam line in 1,2,3# 20 Low each operating any operating each operating loop loop loop

'0 e. Steam Line Pressure - 3/steam line in 2/steam line in 2/steam line in 20 P Negative Rate-High each operating any operating each operating loop loop loop

(0,-. TABLE 3.3-3 (Continued) 0 T-I-

--I ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION 40 M MINIMUM TOTAL NO. CHANNELS CHANNELS APPLICABLE sI FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION 0-I

'Ii 5. Turbine Trip and Feedwater Isolation

a. Automatic Actuation 2 1 2 1, 2 25 Logic and Actuaion Relays

b. Steam Generator 4/stm. gen. 2/stm. gen. 3/stm. gen. 1, 2, 3 20, 21 Water Level -- in each in any oper- in each High-High (P-14) operating ating loop operating loop loop W c. Safety Injection 2 1 2 1, 2 22

0. Actuation Logic

d. Tav, Low Coincident 1 T.. 6/loop 1 Tave in I Tave in 1, 2 20 with P-4 any two any three loops loops

0-4 3 TABLE 3.3-3 (Continued)

FCAo ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION r-.

2 MINIMUM TOTAL NO. CHANNELS CHANNELS APPLICABLE W FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION

6. Auxiliary Feedwater

a. Manual Initiation 2 1 2 1, 2, 3 23

b. Automatic Actuation Logic 2 I 2 1, 2, 3 22 and Actuation Relays

c. Stm. Gen. Water Level--

L~b Low-Low i

W~

1) Start Motor-Driven Pumps 4/stm. gen. 2/stm. gen. 3/stm. gen. 1, 2, 3 20 in any oper- in each ating stm. operating gen. stm. gen.

2) Start Turbine-Driven Pump 4/stm. gen. 2/stm. gen.

in any 2 operating stm. gen.

3/stm. gen.

in each operating stm. gen.

1, 2, 3 20 I

d. Safety Injection See Item 1. above for all Safety Injection initiating functions and Start Motor-Driven requirements.

Pumps

e. Loss-of-Offsite Power 2 1 2 1, 2, 3 19 Start Motor-Driven Pumps

TABLE 3.3-3 (ontinued)

ENGINEERED S,AFETY FEATURES ACTUATION SYSTEM INSTIRUMENTATION MINIMUM TC)TAL NO. CHANNELS CHANNELS APPLICABLE FUNCTIONAL UNIT Of 'CHANNELS TO TRIP OPERABLE MODES ACTION

6. Auxiliary Feedwater (Continued)

f. Containment Depres- See Item 2. above for all CDA functions and requirements.

surization Actuation (CDA) Start Motor-Driven Pumps

7. Control Building Isolation

a. Manual Actuation 2 I 2 19

b. Manual Safety 2 I 2 1, 2, 3, 4 19 Injection Actuation

c. Automatic Actuation 2 1 2 1,2,3,4 14 Logic and Actuation Relays

d. Containment Pressure-- 3 2 2 1,2,3 16

>g High-l

e. Control Building Inlet 2/i ntake I 2/intake 18 Ventilation Radiation

8. Loss of Power

° a. 4kV Bus Under- 4/Abus 2/bus 3/bus 1,2,3,4 27 I voltage-Loss of Voltage

b. 4 kV Bus Undervoltage- 4/ibus 2/bus 3/bus 1,2,3,4 27 I g Grid Degraded Voltage 0o

TABLE 3-1t3 (Contlnuo%

tI ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION MINIMUM TOTAL NO. CHANNELS CHANNELS APPLICABLE FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION

9. Engineering Safety Features Actuation System Interlocks

a. Pressurizer Pressure, 3 2 2 1,2,3 21 P-lI

b. Low-Low Ta.g, P-1 2 4 2 3 1,2,3 21 W

t~j c. Reactor Trip, P-4 2 2 2 1,2,3 23

10. Emergency Generator 2 I 2 1,2,3,4 15 I Load Sequencer B

CD

-3 CD z

l'3

TABLE 3.3-3 (Continued)

TABLE NOTATIONS

1. The Steamline Isolation Logic and Safety Injection Logic for this trip function may be blocked in this MODE below the P-1I (Pressurizer Pressure Interlock) Setpoint.

• MODES 1,2,3,4,5and6.

During fuel movement within containment or the spent fuel pool.

• • • • Trip function automatically blocked above P- Il and may be blocked below P- Il when Safety Injection on low steam line pressure is not blocked.

ACTION STATEMENTS ACTION 14- With the number of OPERABLE channels one less than the Minirnum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />; however, one channel may be bypassed for up to 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> for surveillance testing per Specification 4.3.2.1, provided the other channel is OPERABLE.

ACTION 15 With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />; however, one channel may be bypassed for up to 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> for surveillance testing per Specification 4.3.2.1, provided the other channel is OPERABLE ACTION 16- With the number of OPERABLE channels one less than the Total Number of Channels, operation may proceed until performance of the next required ANALOG CHANNEL OPERATIONAL TEST provided the inoperable channel is placed in the tripped condition within I hour.

ACTION 17- With the number of OPERABLE channels one less than the Total Number of Channels, operation may proceed provided the inoperable channel is placed in the bypassed condition and the Minimum Channels OPERABLE requirement is met. One additional channel may be bypassed for up to 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> for surveillance testing per Specification 4.3.2.1.

ACTION 18- With the number of OPERABLE channels one less than the Total Number of Channels, restore the inoperable channel to OPERABLE status within 7 days.

After 7 days, or if no channels are OPERABLE, immediately suspend fuel movement, if applicable, and be in HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

ACTION 19- With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 48 hours2 days <br />0.286 weeks <br />0.0658 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

MILLSTONE - UNIT 3 3/4 3-24 Amendment No. -,4G, 89, A, 19, 243,

-419, 221

TABLE 3.3-3 (Continued)

ACTION STATEMENTS (Continued)

ACTION 20 - With the number of OPERABLE channels one less than the Total Number of Channels, STARTUP and/or POWER OPERATION may proceed provided the following conditions are satisfied:

a. The inoperable channel is placed in the tripped condition within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />, and

b. the Minimum Channels OPERABLE requirement is met; however, the inoperable channel may be bypassed for up to 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> for surveillance testing of other channels per Specification 4.3.2.1.

ACTION 21 - With less than the Minimum Number of Channels OPERABLE, within I hour determine by observation of the associated permissive annunciator window(s) that the interlock is in its required state for the existing plant condition, or apply Specification 3.0.3.

ACTION 22- With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in at least HOT SHUTDOWN within the following 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />; however, one channel may be bypassed for up to 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> for surveillance testing per Specification 4.3.2.1 provided the other channel is OPERABLE.

ACTION 23 - With the number of OPERABLE channels one less than the Total Number of Channels, restore the inoperable channel to OPERABLE status within 48 hours2 days <br />0.286 weeks <br />0.0658 months <br /> or be in at least HOT STANDBY within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in at least HOT SHUTDOWN within the following 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />.

ACTION 24 - With the number of OPERABLE channels one less than the Total Number of Channels, restore the inoperable channel to OPERABLE status within 48 hours2 days <br />0.286 weeks <br />0.0658 months <br /> or declare the associated valve inoperable and take the ACTION required by Specification 3.7.1.5.

ACTION 25 - With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />; however, one channel may be bypassed for up to 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> for surveillance testing per Specification 4.3.2.1 provided the other channel is OPERABLE.

ACTION 26- DELETED I MILLSTONE- UNIT 3 3/4 3-25 Amendment No. 0, 49, 219

TABLE 3.3-3 (Continued)

ACTION STATEMENTS (Continued)

ACTION 27 - a. With the number of OPERABLE channels one less than the Total Number of Channels, STARTUP and/or POWER OPERATION may proceed provided the following conditions are satisfied:

1. The inoperable channel is placed in the tripped condition within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />, and

2. the Minimum Channels OPERABLE requirement is met; however, the inoperable channel may be bypassed for up to 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> for surveillance testing of other channels per Specification 4.3.2.1.

b. With the number of OPERABLE channels one less than the Minimum Channels required OPERABLE:

1. Place one channel in bypass and other channel in trip condition within one hour and restore one channel to OPERABLE status in 48 hours2 days <br />0.286 weeks <br />0.0658 months <br />, OR

2. Be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

MILLSTONE - UNIT 3 3/4 3-25a Amendment No. 220

o= TABLE 3.3-4 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION TRIP 'SETOINTS C"

cm-I NOMINAL FUNCTIONALYNIT TRIPSETPOINT ALLOWABLE VALUE r, 1. Safety Injection (Reactor Trip, Feedwater Isolation Control Building Isolation IManual (a, Initiation Only) Start Diesel Generators, and gervice Water)

a. Manual Initiation N.A. N.A.

b. Automatic Actuation Logic N.A. N.A.

(a c. Containment Pressure--High I 17.7 psia < 17.9 psia

d. Pressurizer Pressure--Low I) Channels I and II 1892 psia Ž 1889.6 psia 2 Channel III and IV 1892 psia > 1889.6 psia

e. Steam Line Pressure--Low 658.6 psig* > 654.7 psig

2. Containment Spray (CDA)

a. Manual Initiation N.A. N.A.

b. Automatic Actuation Logic N.A. N.A.

and Actuation Relays D c. Containment Pressure--High-3 22.7 psia c 22.9 psia 3 3. Containment Isolation 0 a. Phase "A" Isolation

1) Manual Initiation N.A. N.A.

'0a Iln

ro,,

TAlLE 3E34 0 ENGNEF,RED SAFETY FlATURES ACTUATION SYSTEM INSTRUMENTATION TRIP SETPOINTS z

NOMIINAL U3FUNCTIONAL UNIT T= SETPOINT ALLOWABLE VALUE

3. Containment Isolation (Continued)

2. Automatic Actuation Logic N.A. N.A.

and Actuation Relays

3. Safety Injection See Item 1. above for all Safety Injection Trip Setpoints and Allowable Values.

b. Phase "B" Isolation

1. Manual Initiation N.A. N.A.

M 2. Automatic Actuation N.A. N.A.

Logic and Actuation Relays

3. Containment Pressure- 22.7 psia < 22.9 psia High-3

~z

c. DELETED I

4. Steam Line Isolation

a. Manual Initiation N.A. N.A.

t'C

b. Automatic Actuation Logic N.A. N.A.

and Actuation Relays

c. Containment Pressure-High-2 17.7 psia 5 17.9 psia

d. Steam Line Pressure--Low 658.6 psig* 2 654.7 psig*

CD

e. Steam Line Pressure - 100 psi/s** c 103.9 psi/s**

Negative Rate--High

TABLE ._-4 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION TRIP SETPOINTS NOMINAL FUNCTIONAUNT TRIP SETPOINT ALLOWABLE VALUE I 5. Turbine Trip and Feedwater

'-4 Isolation

-- I W a. Automatic Actuation Logic N.A. N.A.

Actuation Relays

b. Steam Generator Water 80.5% of narrow < 80.8% of narrow Level--High-High (P-14) range instrument range instrument span. span.

c. Safety Injection Actuation See Item 1. above for all Safety Injection Trip Logic Setpoints and Allowable Values.

(A) w (A d. Tave Low Coincident with 5640 F > 563.60F Reactor Trip (P-4)

6. Auxiliary Feedwater

a. Manual Initiation N.A. N.A.

r9 b. Automatic Actuation Logic N.A. N.A.

as and Actuation Relays

=1 C

c. Steam Generator Water Level--Low-Low

1) Start Motor-Driven 18.1% of > 17.8% of narrow Pumps narrow range range instrument span.

instrument span.

TABLE -4 tCotinuedJ 0,

F S r-0 NOMINAL to C.

g FUNCTIONAL UNIT

6. Auxiliary Feedwater (Continued)

IRIP StPOINT ALLALE!ALUE I

2) Start Turbine- 18.1% of > 17.8% of narrow

-4 Driven Pumps narrow range range instrument W* instrument span.

span.

d. Safety Injection See Item I. above for all Safety Injection Trip Setpoints and Allowable Values.

e. Loss-of-Offsite Power 2800V k 2720V Start Motor-Driven Pumps

f. Containment Depressurization See Item 2. above for all CDA Trip Setpoints and Allowable Values.

W Actuation (CDA) Start Motor-Driven Pumps

7. Control Building Isolation 00

a. Manual Actuation N.A N.A.

(as

b. Manual Safety Injection N.A N.A.

Actuation

c. Automatic Actuation N.A. N.A.

Logic and Actuation Relays

d. Containment 17.7 psia < 17.9 psia co Pressure--High I a..s e. Control Building <1.5 x lO0,cpitcc <1.5 x 1&epci/cc Inlet Ventilation Radiation

-'P50 (1'

C~ I..&

UC'\

k " '0

TABLE 3.3-4 (Continued)

ENGINEERED SAFETY FEATURES ACTUATION SYSTEN INSTRUMTATILIP SETPOI S co -

-4 CO NOMINAL z FUNCItONALUNIT

8. Loss of Power TRIP AEJOI ALLOWABLE VALUE I

-I Ed a. 4 kV Bus Undervoltage 2800 > 2720 volts (Loss of Voltage) volts with with a< 2 a < 2 second second time time delay. delay.

b. 4 kV Bus Undervoltage 3730 volts Ž 3706 volts (Grid Degraded Voltage) with a < 8 th a < 8 second time second time delay with ESF delay with ESF actuation or actuation or

< 300 second < 300 second time delay time delay without ESF without ESF W actuation. actuation.

9. Engineered Safety Features Actuation System Interlocks

a. Pressurizer Pressure, P-11 1999.7 psia < 2002.1 psia CL

b. Low-Low Tavgt P-12 553F _ 552.6F

c. Reactor Trip, P-4 N.A. N.A.

3D a 10. Emergency Generator Load N.A.

2M Sequencer N.A.

q ED

. 0

-!' Vl~

p-I.a K_:0G

TABLE 3.3-4 (Continued)

TABLE NOTATIONS

• Time constants utilized in the lead-lag controller for Steam Line Pressure-Low are T, k 50 seconds and T. < 5 seconds. CHANNEL CALIBRATION shall ensure that these time constants are adjusted to these values.

• • The time constant utilized in the rate-lag controller for Steam Line Pressure-Negative Rate-High is greater than or equal to 50 seconds. CHANNEL CALIBRATION I shall ensure that this time constant is adjusted to this value.

NILLSTONE - UNIT 3 3/4 3-31 Amendment No. 134 0456 MARtI 11I iW7-;

This page intentionally left blank MILLSTONE - UNIT 3 3/4 3-32 Amendment No. l 91 sole

This page intentionally left blank MILLSTONE - UNIT 3 80?0 3/4 3-33 Amendment No. t 91

This page intentionally left blank MILLSTONE - UNIT 3 3/4 3-34 Amendment No. 1P. Z.9 1i, 91 00?o

This page Intentionally left blank IILLSTONE - UNIT 3 3/4 3-35 Amendment No. , 91 080?03433

0

-J M-F-. TABLE 4.3-2 r-40 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS (A

TRIP

-_4 ANALOG ACTUATING MODES LO CHANNEL DEVICE MASTER SLAVE FOR WHICH CHANNEL CHANNEL OPERATIONAL OPERATIONAL ACTUATION RELAY RELAY SURVEILLANCE FUNCTIONAL UNIT CHECK CALIBRATION TEST TEST LOGIC TEST TEST TEST IS REQUIRED

1. Safety Injection (Reactor Trip, Feedwater Isolation, Control Building Isolation (Manual Initiation Only), Start Diesel Generators, and Service Water)

a. Manual Initiation N.A. N.A. N.A. R N.A. N.A. N.A. 1, 2, 3, 4

b. Automatic Actuation N.A. N.A. N.A. N.A. M(1) M(1) Q(4) 1, 2, 3, 4  !

Logic and Actuation W Relays

c. Containment Pressure- S R Q N.A. N.A. N.A. N.A. 1, 2, 3 a'. High-I

d. Pressurizer Pressure- S R Q N.A. N.A. N.A. N.A.

Low 1, 2, 3

e. Steam Line S R Q N.A. N.A. N.A. N.A. 1, 2, 3 Pressure-Low

2. Containment Spray is a. Manual Initiation N.A. N.A. N.A. R N.A. N.A. N.A. 1, 2, 3, 4 ft b. Automatic Actuation N.A. N.A. N.A. N.A. M(1) M(1) Q(4) 1, 2, 3, 4 aCL Logic and Actuation Relays 0

c. Containment Pressure- S R Q N.A. N.A. N.A. N.A. 1, 2, 3, 4 High-3

-A 1-hao I"

MI. 43-2 (Continned)

ENGINEERED SAFEITY FEATURES ACTUATION SYSTEM INSTRUMENTATION SURVEILLANCE REOUIR-EMEN15 TRIP ANALOG ACTUATING MODES C-4 co CHANNEL DEVICE MASTER SLAVE FOR WHICH CHANNEL CHANNEL OPERATIONAL OPERATIONAL ACIUATION RELAY RELAY SURVEILLANCE 3 FUNCTIONALUNIT CHECK CALIBRATION TEST ESl.T LOGIC TEST TEST TEST IS REQUIRED 3 3. Containment Isolation

.-q a. Phase "A" Isolation w

1. Manual Initiation N.A. N.A. N.A. R N.A. N.A. N.A. 1, 2,3,4

2. Automatic Actuation N.A. N.A. N.A. N.A. M(l) M(l) Q(4) 1,2,3,4 Logic and Actuation Relays

3. Safety Injection See Item 1. above for all Safety Injection Surveillance Requirements.

-J b. Phase "B" Isolation

1. Manual Initiation N.A. N.A. N.A. R N.A. N.A. N.A. 1, 2,3,4

2. Automatic Actuation N.A. N.A. NA. N.A. M(l) M(l) Q(4) 1,2,3,4 Logic and Actuation Relays

3. Containment S R Q N.A. N.A. N.A. N.A. 1,2,3,4 Pressure-High-3 z0o

c. DELETED I

4. Steam Line Isolation

d. Manual Initiation

1. Individual N.A. N.A. N.A. R N.A. N.A. N.A. 1, 2,3,4

2. System N.A. N.A. N.A. R N.A. N.A. N.A. 1,2,3,4

TABLE 4.3-2 (Continued) o 4.4

=

at o

WI-

-1i ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS z

TRIP ANALOG ACTUATING MODES COJ CHANNEL DEVICE MASTER SLAVE FOR WHICH

-4 CHANNEL CHANNEL OPERATIONAL OPERATIONAL ACTUATION RELAY RELAY &JMLUME FUNCTIONAL UNIT CHECK CALIBRATION TEST TEST LOGIC TEST TEST TEST IS REDlJIIM

4. Steam Line Isolation (Continued)

b. Automatic Actuation N.A. N.A. N.A. N.A. M(1) M(1) Q(4) 1, 2, 3, 41 Logic and Actuation Relays

c. Containment Pressure- S R Q N.A. N.A. N.A. N.A. 1, 2, 3, 4 High-2 1.p

d. Steam Line S R Q N.A. N.A. N.A. N.A. 1, 2, 3 Pressure-Low

e. Steam Line Pressure- S R Q N.A. N.A. N.A. N.A. 3 c:

Negative Rate-High

5. Turbine Trip and Feedwater Isolation 3 a. Automatic Actuation II . r, . N.A. N.A. N.A. M(1) M(1) Q(4) 1, 2 1 Logic and Actuation M Relays

b. Steam Generator Water S R Q N.A. M(1) 1, 2, 3 r0 Level-High-High M(1) Q(4) 1

c. Safety Injection N.A. N.A. N.A. R N.A. N.A. N.A. 1, 2

-z Actuation Logic

-Q

d. Tave Low Coincident N.A. R Q N.A. N.A. N.A. N.A. 1, 2

-4 with Reactor Trip (P-4)

Cd

o 3 TABLE 4.3-2 (Continued)

ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS TRIP I ANALOG ACTUATING MODES CHANNEL DEVICE MASTER SLAVE FOR WHICH CHANNEL CHANNEL OPERATIONAL OPERATIONAL ACTUATION RELAY RELAY SURVEILLANCE FUNCTIONAL UNIT CHECK CALIBRATION TEST TEST LOGIC TEST TEST TEST IS REQUIRED

6. Auxiliary Feedwater

a. Manual Initiation N.A. N.A. N.A. R N.A. N.A. N.A. 1, 2, 3

b. Automatic Actuation N.A. N.A N.A. N.A. M(1) M(1) Q(4) 1, 2, 3 and Actuation Relays I-

c. Steam Generator Water S R Q N.A. N.A. N.A. N.A. 1, 2, 3 Level-Low-Low

d. Safety Injection See Item 1. above for all Safety Injection Surveillance Requirements.

-I

e. Loss-of-Offsite Power See Item 8. below for all Loss of Power Surveillance.

to

f. Containment Depres- See Item 2. above for all CDA Surveillance Requirements.

surization Actuation (CDA)

7. Control Building Isolation

a. Manual Actuation N.A. N.A. N.A. R N.A. N.A. N.A.

=.

b. Manual Safety N.A. N.A. N.A. R N.A. N.A. N.A. 1, 2, 3, 4

> Injection Actuation

c. Automatic Actuation N.A. N.A. N.A. N.A. M(1) M(1) Q(4) 1, 2, 3, 4 S8^ Logic and Actuation

• Relays cr d. Containment Pressure-- S R Q N.A. N.A. N.A. N.A. 1, 2, 3 aq High-l

o 3

~jm- 1 TABLE 4.3-2 (Continued)

ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION

-I 0 SURVEILLANCE REQUIREMENTS Z

cn TRIP

-I ANALOG ACTUATING MODES CA CHANNEL DEVICE MASTER SLAVE FOR WHICH CHANNEL CHANNEL OPERATIONAL OPERATIONAL ACTUATION RELAY RELAY SURVEILLANCE FUNCTIONAL UNIT CHECK CALIBRATION TEST TEST LOGIC TEST TEST TEST IS REQUIRED

7. Control Building Isolation (Continued)

e. Control Building Inlet S R Q N.A. N.A. N.A. N.A.

• I Ventilation Radiation

8. Loss of Power

a. 4 kV Bus N.A. R N.A M(3) N.A. N.A. N.A. 1, 2, 3, 4 Undervoltage (Loss of Voltage)

b. 4 kV Bus N.A. R N.A. M(3) N.A. N.A. N.A. 1, 2, 3, 4 Undervoltage (Grid Degraded Voltage) o

9. Engineered Safety Features Actuation System Interlocks

a. Pressurizer N.A. R Q N.A. N.A. N.A. N.A. 1, 2, 3

30. Pressure, P-11 0

b. Low-Low Tavg, P-12 N.A. R N.A. N.A. N.A. N.A. 1, 2, 3 F c. Reactor Trip, P-4 N.A. N.A. N.A. R N.A. N.A. N.A. 1, 2, 3 0 1o Emergency Generator N.A. N.A. N.A. N.A. Q(1, 2) N.A. N.A. 1, 2, 3, 4 Load Sequencer 10

"-4

-Q

TABLE 4.3-2 (Continued)

TABLE NOTATION

1. Each train shall be tested at least every 62 days on a STAGGERED TEST BASIS.

2. This surveillance may be performed continuously by the emergency generator load sequencer auto test system as long as the EGLS auto test system is demonstrated operable by the performance of an ACTUATION LOGIC TEST at least once per 92 days.

3. On a monthly basis, a loss of voltage condition will be initiated at each undervoltage monitoring relay to verify individual relay operation. Setpoint verification and actuation of the associated logic and alarm relays will be performed as part of the channel calibration required once per 18 months.

4. For Engineered Safety Features Actuation System functional units with only Potter &

Brumfield MDR series relays used in a clean, environmentally controlled cabinet, as discussed in Westinghouse Owners Group Report WCAP- 13900, the surveillance interval for slave relay testing is R.

• MODES 1,2,3,4,5and6.

During fuel movement within containment or the spent fuel pool.

MILLSTONE - UNIT 3 3/4 3-41 Amendment No. 4, 74, 79, 00, 4-29, 4-98,203,249 claacrtto, 'Utt'r-, C-1, '7 -c ,it.q

INSTRUMENTATION 3/4.3.3 MONITORING INSTRUMENTATION RADIATION MONITORING FOR PLANT OPERATIONS LIMITING CONDITION FOR OPERATION 3.3.3.1 The radiation monitoring instrumentation channels for plant operations shown in Table 3.3-6 shall be OPERABLE with their Alarm/Trip Setpoints within the specified limits.

APPLICABILITY: As shown in Table 3.3-6.

ACTION:

a. With a radiation monitoring channel Alarm/Trip Setpoint for plant operations exceeding the value shown in Table 3.3-6, adjust the Setpoint to within the limit within 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> or declare the channel inoperable.

b. With one or more radiation monitoring channels for plant operations inoperable, take the ACTION shown in Table 3.3-6.

c. The provisions of Specification 3.0.3 are not applicable.

I SURVEILLANCE REQUIREMENTS 4.3.3.1 Each radiation monitoring instrumentation channel for plant operations shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL CALIBRATION and ANALOG CHANNEL OPERATIONAL TEST for the MODES and at the frequencies shown in Table 4.3-3.

MILLSTONE - UNIT 3 3/4 3-42 AMENDMENT NO. 57 e';', ,. 5 4cg

imaLE 3.3-6 o =

RADIATION MONITORING INSTRUMENTATION FOR PLANT OPERATIONS CA

-I 40 mn MINIMUM CHANNELS CHANNELS APPLICABLE ALARM/TRIP E-UNCIIONAL UNIT TO TRIP/ALARM OPERABLE MODES SETPOINT 6CULON

1. Containment

a. Deleted I

b. RCS Leakage Detection Ir

-I

1) Particulate Radioactivity N.A. 1 1, 2, 3, 4 N.A. 29

2) Gaseous Radioactivity N.A. I 1, 2, 3, 4 N.A. 29

2. Fuel Storage Pool Area Monitors

a. Radiation Level 1 2 c 15 mR/h 28 D

=i~B.

CD I--, f ClI\)

IC~t

TABLE 3.3-6 (Continued)

TABLE NOTATIONS

• With fuel in the fuel storage pool areas.

ACTION STATEMENTS ACTION 27 - Not used. I ACTION 28 - With less than the Minimum Channels OPERABLE requirement, fuel movement may continue for up to 30 days provided an appropriate portable continuous monitor with the same Alarm Setpoint is provided in the fuel storage pool area. Restore the inoperable monitors to OPERABLE status within 30 days or suspend all operations involving fuel movement in the fuel storage pool areas.

ACTION 29 - With the number of OPERABLE Channels less than the Minimum Channels OPERABLE requirement, comply with the ACTION requirements of Specification 3.4.6.1.

MILLSTONE - UNIT 3 3/4 3-44 Amendment No. fle 129 0384 2 7 1998 J)U'U

CZ TABLE 4.3-3 RADIATION MONITORING INSTRUMENTATION FOR PLANT 1-4 OPERATIONS SURVEILLANCE REQUIREMENTS CA ANALOG

-4 CHANNEL MODES FOR WHICH CHANNEL CHANNEL OPERATIONAL SURVEILLANCE FUNCTIONAL UNIT CHECK CALIBRATION TEST IS REQUIRED to~ 1. Containment

a. Deleted

b. RCS Leakage Detection

1) Particulate Radio- S R Q 1, 2, 3, 4 activity

2) Gaseous Radioactivity S R Q 1, 2, 3, 4 UP (a)b 2. Fuel Storage Pool Area Monitors UP~

a. Radiation Level S R Q

• TABLE NOTATIONS 3

• With fuel in the fuel storage pool area.

5 V.

eD

'a C-,

,o

THIS PAGE LEFT BLANK INTENTIONALLY MILLSTONE - UNIT 3 0714 3/4 3-46 AMENDMENT No. 7,193

THIS PAGE LEFT BLANK INTENTIONALLY 4ILLSTONE - UNIT 3 3/4 3-47 AMENDMENT No. P7,193 0714

THIS PAGE LEFT BLANK INTENTIONALLY MILLSTONE - UNIT 3 3/4 3-48 Amendment No.-?f,193 0714

THIS PAGE LEFT BLANK INTENTIONALLY MILLSTONE - UNIT 3 3/4 3-49 Amendment No. 77, Ypp,193 0714

THIS PAGE LEFT BLANK INTENTIONALLY MILLSTONE - UNIT 3 3/4 3-50 AMENDMENT No. 7,193 0714

THIS PAGE LEFT BLANK INTENTIONALLY MILLSTONE - UNIT 3 3/4 3-51 Amendment No.193 0714

THIS PAGE LEFT BLANK INTENTIONALLY MILLSTONE - UNIT 3 3/4 3-52 Amendment No.193

• 0714

INSTRUMENTATION RENOTE SHUTDOWN INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.3.5 The Remote Shutdown Instrumentation transfer switches, power, controls and monitoring instrumentation channels shown in Table 3.3-9 shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTION:

a. With the number of OPERABLE remote shutdown monitoring channels less than the Minimum Channels OPERABLE as required by Table 3.3-9, restore the inoperable channel(s) to OPERABLE status within 7 days, or be in HOT SHUTDOWN within the next 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />.

b. With one or more Remote Shutdown Instrumentation transfer switches, power, or control circuits inoperable, restore the inoperable switch(s)/circuit(s) to OPERABLE status within 7 days, or be in HOT STANDBY within the next 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />.

c. Entry into an OPERATIONAL MODE is permitted while subject to these ACTION requirements.

SURVEILLANCE REQUIREMENTS 4.3.3.5.1 Each remote shutdown monitoring instrumentation channel shall be demonstrated OPERABLE by performance of the CHANNEL CHECK and CHANNEL CALIBRATION operations at the frequencies shown in Table 4.3-6.

4.3.3.5.2 Each Remote Shutdown Instrumentation transfer switch, power and control circuit including the actuated components, shall be demonstrated OPERABLE at least once per 18 months. I MILLSTONE - UNIT 3 3/4 3-53 Amendment No. F7, 7i, 100 am4 3 1995 MANt

TABLE 3.3-9 REMOTE SHUTDOWN INSTRUMENTATION In TOTAL NO. MINIMUM I READOUT OF CHANNELS INSTRUMENT LOCATION CHANNELS OPERABLE

-4

1. Reactor Trip Breaker Indication Reactor Trip Switchgear 1/trip breaker 1/trip breaker

-a

2. Pressurizer Pressure Aux. Shutdown Panel 2 1

3. Pressurizer Level Aux. Shutdown Panel 2 I

4. Steam Generator Pressure Aux. Shutdown Panel 2/steam generator 1/steam generator

5. Steam Generator Water Level Aux. Shutdown Panel 2/steam generator I/steam generator

6. Auxiliary Feedwater Flow Rate Aux. Shutdown Panel 1/steam generator I/steam generator

7. Loop Hot Leg Temperature Aux. Shutdown Panel 1/loop 1/loop

8. Loop Cold Leg Temperature Aux. Shutdown Panel 1/loop I/loop

9. Reactor Coolant System Pressure Aux. Shutdown Panel 2 1 (Wide Range)

10. DWST Level Aux. Shutdown Panel 2 1 up 11. RWST Level Aux. Shutdown Panel 2 1

12. Containment Pressure Aux. Shutdown Panel 2 I W' 13. Emergency Bus Voltmeters Aux. Shutdown Panel 1/train I/train U', 14. Source Range Count Rate Aux. Shutdown Panel 2 1

15. Intermediate Range Flux Aux. Shutdown Panel 2 1

16. Boric Acid Tank Level Aux. Shutdown Panel 2/tank 1/tank TRMNSFER SWITCHES SWITCH LOCATION

1. Auxiliary Feedwater Isolation FWA*MOV35A Transfer Switch Panel

2. Auxiliary Feedwater Isolation FWA*MOV35B Transfer Switch Panel

3. Auxiliary Feedwater Isolation FWA*MOV35C Transfer Switch Panel

4. Auxiliary Feedwater Isolation FWA*MOV35D Transfer Switch Panel

5. Auxiliary Feedwater Pump Ah. Suction FWA*AOV23A Transfer Switch Panel rt 6. Auxiliary Feedwater Pump Ah. Suction 0 FWA*AOV23B Transfer Switch Panel a,.

TABLE 3.3-9 (Continued)

I- REMOTE SHUTDOWN INSTRUMENTATION I-4 0

TRANSFER SWITCHES SWITCH m LOCATION

7. Turbine Driven Pump Steam Supply z MSS*AOV31A Transfer Switch Panel 1-4

--4 8. Turbine Driven Pump Steam Supply MSS*AOV31B Transfer Switch Panel

9. Turbine Driven Pump Steam Supply MSS*AOV31D Transfer Switch Panel

10. Reactor Vessel Head Vent Isolation rn RCS*SV8095A Transfer Switch Panel

11. Reactor Vessel Head Vent Isolation RCS*SV8095B Transfer Switch Panel

12. Reactor Vessel Head Vent Isolation RCS*SV8096A Transfer Switch Panel NP. 13. Reactor Vessel Head Vent Isolation WA RCS*SV8096B Transfer Switch Panel

'3' 14. Reactor Vessel to Excess Letdown VI' RCS*MV8098 Transfer Switch Panel

15. Pressurizer Level Control RCS*LCV459 Transfer Switch Panel

16. Pressurizer Level Control RCS*LCV460 Transfer Switch Panel

17. Letdown Orifice Isolation CHS*AV8149A Transfer Switch Panel

18. Letdown Orifice Isolation CHS*AV8149B Transfer Switch Panel

19. Letdown Orifice Isolation CHS*AV8149C Transfer Switch Panel

20. Volume Control Tank Outlet Isolation CHS*LCV112B Transfer Switch Panel

21. Volume Control Tank Outlet Isolation CHS*LCV112C Transfer Switch Panel

22. RWST to CHS Pump Suction CHS*LCV112D Transfer Switch Panel

23. RWST to CHS Pump Suction CHS*LCV112E Transfer Switch Panel

24. Aharging to RCS Isolation CHS*AV8146 Transfer Switch Panel

25. Charging to RCS Isolation CHS*AV8147 Transfer Switch Panel

26. Boric Acid Gravity Feed CHS*MV8507A Transfer Switch Panel

27. Boric Acid Gravity Feed CHS*MV8507B Transfer Switch Panel

TABLE 3.3-9 (Continued)

I- REMOTE SHUTDOWN INSTRUMENTATION (A.

--4 0 TRANSFER SWITCHES SWITCH m LOCATION

28. Charging Header Isolation Bypass CHS*MV8116 Transfer Switch Panel

--I 29. Pressurizer Heater Backup RCS*H1A

(&) (Group A) Transfer Switch Panel

30. Pressurizer Heater Backup RCS*H1B (Group B) Transfer Switch Panel CONTROL CIRCUITS SWITCH LOCATION

1. Auxiliary Feedwater Flow Control FWA*HV31A Auxiliary Shutdown Panel La

2. Auxiliary Feedwater Flow Control co FWA*HV31B Auxiliary Shutdown Panel La)

3. Auxiliary Feedwater Flow Control 0.3 FWA*HV31C Auxiliary Shutdown Panel

4. Auxiliary Feedwater Flow Control FWA*HV31D Auxiliary Shutdown Panel

5. Auxiliary Feedwater Flow Control FWA*HV32A Auxiliary Shutdown Panel

6. Auxiliary Feedwater Flow Control FWA*HV32B Auxiliary Shutdown Panel

7. Auxiliary Feedwater Flow Control FWA*HV32C Auxiliary Shutdown Panel

8. Auxiliary Feedwater Flow Control FWA*HV32D Auxiliary Shutdown Panel

9. Auxiliary Feedwater Flow Control FWA*HV36A Auxiliary Shutdown Panel

10. Auxiliary Feedwater Flow Control FWA*HV36B Auxiliary Shutdown Panel

11. Auxiliary Feedwater Flow Control FWA*HV36C Auxiliary Shutdown Panel

12. Auxiliary Feedwater Flow Control FWA*HV36D Auxiliary Shutdown Panel

TABLE 3.3-9 (Continued)

I-I-0 REMOTE SHUTDOWN INSTRUMENTATION

(/1

-- 4 m CONTROL CIRCUITS SWITCH LOCATION I

13. Reactor Vessel to PRT Control RCS*HCV442A Auxiliary Shutdown Panel

--I WA

14. Reactor Vessel to PRT Control RCS*HCV442B Auxiliary Shutdown Panel

15. Charging Header Flow Control CHS*HCV19OA Auxiliary Shutdown Panel

16. Charging Header Flow Control CHS*HCV19OB Auxiliary Shutdown Panel

17. Excess Letdown Flow Control CHS*HCV123 Auxiliary Shutdown Panel

18. Charging Flow Control CHS*FCV121 Auxiliary Shutdown Panel

19. Low Pressure Letdown Control CHS*PCV131 Auxiliary Shutdown Panel CA 1-r.

CA

TABLE-4.3-6 REMOTE SHUTDOWN HONITORING INSTRUNENTATION SURVEILLANCE REQUIREMENTS CHANNEL CHANNEL INSTRUMENT

• -CHE CALIBRATION W 1. Reactor Trip Breaker Indication M N.A.

• 2. Pressurizer Pressure N R

3. Pressurizer Level N R

4. Steam Generator Pressure N R

5. Steam Generator Water Level N R

6. Auxiliary Feedwater Flow Rate M R

7. Loop Hot Leg Temperature N R

8. Loop Cold Leg Temperature N R

9. Reactor Coolant System Pressure N R (Wide Range)

10. DWST Level N R

11. RWST Level M R

12. Containment Pressure M R

13. Emergency Bus Voltmeters N R

14. Source Range Count Rate M* R

15. Intermediate Range Amps N R g 16. Boric Acid Tank Level M R R

• When below P-6 (intermediate range neutron flux Interlock setpoint).

0

lN83RMEIO ACCEDENT MONITORING INSTRUMNATION LIMITING CONDITION FOR OPERATION 3.3.3.6 The accident monitoring instrumentation channels shown in Table 3.3-10 shall be OPERABLE.

E ELICABILE MODES 1, 2, and 3.

AMION:

a. With the number of OPERABLE accident monitoring instrumentation channels except the containment area high range radiation monitor, and reactor vessel water level, less than the Total Number of Channels shown in Table 3.3-10, restore the inoperable channel(s) to OPERABLE status within 7 days, or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in at least HOT SHUTDOWN within the following 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />.

b. With the number of OPERABLE accident monitoring instrumentation channels "except the containment area-high range radiation monitor, and reactor vessel water level less than the Minimum Chanels OPERABLE requirements of Table 3.3-10, restore the inoperable chanmel(s) to OPERABLE status within 48 hours2 days <br />0.286 weeks <br />0.0658 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in at least HOT SHUTDOWN within the following 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />.

c. With the number of OPERABLE chamels for the containment area-high range radiation monitor less than required by either the total or the Minimum Channels OPERABLE requirements, initiate an alternate method of monitoring the appropriate parameter(s), within 72 hours3 days <br />0.429 weeks <br />0.0986 months <br />, and either restore the inoperable channel(s) to OPERABLE status wihin 7 days or prepare and submit a Special Report to the Commission, pursuant to Specification 6.9.2, within 14 days that provides actions taken, cause of the inoperability, and the plans and schedule for restoring the channels to OPERABLE status.

d. Deleted

e. With the number of OPERABLE channels for the reactor vessel water level monitor less than the Total number of Channels shown in Table 3.3-10, either restore the inoperable channel to OPERABLE status within 7 days if repairs are feasible without shutting down or prepare and subnit a Special Report to the Commission pursuant to Specification 6.9.2 within 30 days following the event outlining the MILLSTONE - UNIT 3 3/4 3-59 Amendment No. 47, , %;,224

LIMITING CONDITION FOR OPERATION (Continued) action taken, the cause of the inoperability, and the plans and schedule for restoring the channel to OPERABLE status.

f. With the number of OPERABLE channels for the reactor vessel water level monitor less than the minimum channels OPERABLE requirements of Table 3.3-10, either restore the inoperable channel(s) to OPERABLE status within 48 hours2 days <br />0.286 weeks <br />0.0658 months <br /> if repairs are feasible without shutting down or.

1. Initiate an alternate method ofmonitoring the reactor vessel inventory;

2. Prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within 30 days following the event outlining the action taken, the cause ofthe inoperability, and the plans and schedule for restoring the channel(s) to OPERABLE status; and

3. Restore the channel(s) to OPERABLE status at the next scheduled refueling.

g. Entry into an OPERATIONAL MODE is permitted while subject to these ACTION requirements.

SURVEILLANCE REQUIREMENTS 4.3.3.6.1 Each accident monitoring instrumentation channel shall be demonstrated OPERABLE by performance of the CHANNEL CHECK and CHANNEL CALIBRATION at the frequencies shown in Table 4.3-7.

4.3.3.6.2 Deleted MILLSTONE - UNIT 3 3/4 3-59a AmendmentNo. 47, R4,6, 4Y 224

a t-.

TABLE 3.3-10 t-.

Cn a

0 ACCIDENT MONITORING INSTRUMENTATION TOTAL MINIMUM NO. OF CHANNELS C INSTRUMENT CHANNELS OPERABLE w 1. Containment Pressure

a. Normal Range 2 I

b. Extended Range 2 I 0- 2. Reactor Coolant Outlet Temperature - T"OT (Wide Range) 2 I

3. Reactor Coolant Inlet Temperature - TCOLD (Wide Range) 2 I

4. Reactor Coolant Pressure - Wide Range 2 1 w

5. Pressurizer Water Level 2 ta, 0%

6. Steam Line Pressure 2/steam generator I/steam generator.

7. Steam Generator Water Level - Narrow Range 1/steam generator I/steam generator

8. Steam Generator Water Level - Wide Range 1/steam generator I/steam generator i.3

9. Refueling Water Storage Tank Water Level 2 I

-I (0

10. Demineralized Water Storage Tank Water Level 2 I 03 AD+

I." 11. Auxiliary Feedwater Flow Rate 2/steam generator F

1/steam generator CO to -P.

12. Reactor Coolant System Subcoollng Margin Monitor 2 I

13. Containment Water Level (Wide Range) 2 I

14. Core Exit Thermocouples 4/core quadrant 2/core quadrant

15. DELETED I

TABBLE 3.310 (ConntnuedL 03 RMMMONTRN INST RUMNTATIODI a ACIDENT TOTAL MINIMUM NO. OF CHANNELS CHANLS OPERABLE 11 16. Contauin ient Area - High Range Radiation Monitor 2 I

17. Reactor Vessel Water Level 2* 1*

18. Deleted I

19. Neutron Fhlx 2 I w

6%

• A channel consists of eight sensors ina probe. A channel is operable if four or more sensors, half or more in the upper head region and half or more in the upper plenwm region, are operable.

I I

K%3

. .: I

, .1 :;. I!I . I

TABLE 4.3-7 ACCIOTM ITORIG INSUMETATMIg SURVEILLM-CE REOUIREENS CHANNEL CHANNEL INSTRUMENT CHECK CALIBBMTION

1. Containment Pressure

a. Normal Range

b. Extended Range

2. Reactor Coolant Outlet Temperature - TcT (Wide Range)

3. Reactor Coolant Inlet Temperature - Tcm (Wide Range)

4. Reactor Coolant Pressure - Wide Range

5. Pressurizer Water Level

6. Steam Line Pressure 31%)

W

7. Steam Generator Water Level - Narrow Range

8. Steam Generator Water Level - Wide Range

9. Refueling Water Storage Tank Water Level

10. Demineralized Water Storage Tank Water Level

-. Mb

11. Auxiliary Feedwater Flow Rate

12. Reactor Coolant System Subcooling Margin Monitor U..

I. 13. Containment Water Level (Wide Range)

-. 0 14. Core Exit Thermocouples t  ? 15. DELETED 40 CD CO

IMBLE W(Contnus ACC)ENT MIONUORING INST^RUMENTATION SURVEILLANCE: REOIURESNME CHANNEL CHANNEL CALDlM wI 16. Containment Area - High Range Radiation Monitor M

17. Reactor Vessel Water Level M

18. Deleted I

19. Neutron Flux M R

$LaJ

• CHANNEL CALIBRAIION may consist ofan electronic calibration of the channel, not including the detector, for range decades above 10 R/h and a one point calibration check of the detector below 10 R/h with an installed or portable gamma source.

• • Electronic calibration from the ICC cabinets only.

I a

I.J P~

This page intentionally left blank MILLSTONE - UNIT 3 3/4 3-64 Amendment No. Af 57,84 fl C,. 4 -

_ ^

This page intentionally left blank MILLSTONE - UNIT 3 3/4 3-65 Amendment No. }0, #g,84

This page intentionally left blank MILLSTONE - UNIT 3 3/4 3-66 Amendment No. A 8

This page intentionally left blank MILLSTONE - UNIT 3 3/4 3-67 Amendment No. f', 84

THIS PAGE LEFT BLANK INTENTIONALLY MILLSTONE - UNIT 3 3/4 3-68 0715 Amendment No. 17. 77, iPP, Jig, 193

This page intentionally left blank MILLSTONE - NIT 3 3/4 3-69 Amendment No. XX, F7, P1,188 0692

This page intentionally left blank MILLSTONE - UNIT 3 0e92 3/4 3-70 Amendment No. 7X188

This page intentionally left blank MILLSTONE - UNIT 3 3/4 3-71 0692 Amendment No. 18 8

.: j-. 3

This page intentionally left blank MILLSTONE - UNIT 3 3/4 3-72 Amendment No.188 0892

This page intentionally left blank MILLSTONE - UNIT 3 3/4 3-73 Amendment No.- 188 0892

This page intentionally left blank MILLSTONE - UNIT 3 3/4 3-74 Amendment No. p7,, f,188 0892

This page intentionally left blank MILLSTONE - UNIT 3 3/4 3-75 0892 Amendment No.188

This page intentionally left blank MILLSTONE - UNIT 3 3/4 3-76 Amendment No. 188 0692

This page intentionally left blank MILLSTONE - UNIT 3 3/4 3-77 Amendment No. 2,188 01392

This page intentionally left blank MILLSTONE - UNIT 3 3/4 3-78 0692 Amendment No.188

This page intentionally left blank MILLSTONE - UNIT 3 3/4 3-79 0692 knendment No. 188

This page intentionally left blank KILLSTONE - UNIT 3 3/4 3-80 Amendment No.188 0692

THIS PAGE LEFT BLANK INTENTIONALLY MILLSTONE - UNIT 3 3/4 3-81 Amendment No. If, 17;.193 0n1e

INSTRUMENTATION 3/4.3.5 SHUTDOWN MARGIN MONITOR LIMITING CONDITION FOR OPERATION 3.3.5 Two channels of Shutdown Margin Monitors shall be OPERABLE

a. With a minimum count rate as designated in the CORE OPERATING LIMITS REPORT (COLR), or

b. If the minimum count rate in Specification 3.3.5.a cannot be met, then the Shutdown Margin Monitors may be made operable with a lower minimum count rate, as specified in the COLR, by borating the Reactor Coolant System above the requirements of Specification 3.1.1.1.2 or 3.1.1.2. The additional boration shall be:

1. A minimum of 150 ppm above the SHUTDOWN MARGIN requirements specified in the COLR for MODE 3, or

2. A minimum of 350 ppm above the SHUTDOWN MARGIN requirements specified in the COLR for MODE 4, MODE 5 with RCS, loops filled, and MODE 5 with RCS loops not filled.

APPLICABILITY: MODES 3*, 4, and 5.

ACTION:

a. With one Shutdown Margin Monitor inoperable, restore the inoperable channel to OPERABLE status within 48 hours2 days <br />0.286 weeks <br />0.0658 months <br />.

b. With both Shutdown Margin Monitors inoperable or one Shutdown Margin Monitor inoperable for greater than 48 hours2 days <br />0.286 weeks <br />0.0658 months <br />, immediately suspend all operations involving positive reactivity changes via dilution and rod withdrawal.

Verify the valves listed in Specification 4.1.1.2.2 are closed and secured in position within the next 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> and at least once per 14 days thereafter.**

Verify compliance with the SHUTDOWN MARGIN requirements of Specification 3.1.1.1.2 or 3.1.1.2, as applicable, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> thereafter.

• The shutdown margin monitors may be blocked during reactor startup in accordance with approved plant procedures.

• The valves may be opened on an intermittent basis under administrative controls as noted in Surveillance 4.1.1.2.2.

MILLSTONE - UNIT 3 314 3-82 Amendment No. 1-64, 217, 218

INSTRUMENTATION 3/4.3.5 SHUTDOWN MARGIN MONITOR (continued)

SURVEILLANCE REQUIREMENTS 4.3.5 a. Each of the above required shutdown margin monitoring instruments shall be demonstrated OPERABLE by an ANALOG CHANNEL OPERATIONAL TEST at least once per 92 days that shall include verification that the Shutdown Margin Monitor is set per the Core Operating Limits Report (COLR).

b. At least once per 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> VERIFY the minimum count rate (counts/sec) as defined within the COLR.

MILLSTONE - UNIT 3 3/4 3-83 Amendment No.164l 0495 -' -I

3/4.4 REACTOR COOLANT SYSTEM 3/4.4.1 REACTOR COOLANT LOOPS AND COOLANT CIRCULATION STARTUP AND POWER OPERATION I I 1mmTTNA rnNnTTInN FnR RPFRATTAN 3.4.1.1 Four reactor coolant loops shall be OPERABLE and in operation. I I

APPLICABILITY: MODES I and 2.*

ACTION:

With less than the above required reactor coolant loops in operation, be in at least HOT STANDBY within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />.

eIRVFJI I ANCF RFQII1RFMFIrT 4.4.1.1 The above required reactor coolant loops shall be verified in operation and circulating reactor coolant at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />.

• See Special Test Exceptions Specification 3.10.4.

MILLSTONE - UNIT 3 3/4 4-1 Amendment No.217 0981

REACTOR COOLANT SYSTEM HOT STANDBY LIMITING CONDITION FOR OPERATION 3.4.1.2 At least three of the reactor coolant loops listed below shall be OPERABLE, with at least three reactor coolant loops in operation when the Control Rod Drive System is capable of rod withdrawal or with at least one reactor coolant loop in operation when the Control Rod Drive System is not capable of rod withdrawal:* I

a. Reactor Coolant Loop 1 and its associated steam generator and reactor coolant pump,

b. Reactor Coolant Loop 2 and its associated steam generator and reactor coolant pump,

c. Reactor Coolant Loop 3 and its associated steam generator and reactor coolant pump, and

d. Reactor Coolant Loop 4 and its associated steam generator and reactor coolant pump.

APPLICABILITY: MODE 3.

ACTION:

a. With less than the above required reactor coolant loops OPERABLE, restore the required loops to OPERABLE status within 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> or be in HOT SHUTDOWN within the next 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />.

b. With less than the above required reactor coolant loops in operation and the Control Rod Drive System is capable of rod withdrawal, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> open the Reactor Trip System breakers.

c. With no reactor coolant loop in operation, suspend all operations involving a reduction in boron concentration of the Reactor Coolant System and immediately initiate corrective action to return the required reactor coolant loop to operation.

SURVEILLANCE REQUIREMENTS 4.4.1.2.1 At least the above required reactor coolant pumps, if not in operation, shall be determined OPERABLE once per 7 days by verifying correct breaker alignments and indicated power availability.

4.4.1.2.2 The required steam generators shall be determined OPERABLE by verifying secondary side water level to be greater than or equal to 17% at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />.

4.4.1.2.3 The required reactor coolant loops shall be verified in operation and circulating reactor coolant at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />.

• All reactor coolant pumps may be deenergized for up to 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> provided:

(1) no operations are permitted that would cause dilution of the Reactor Coolant System boron concentration, and (2)core outlet temperature is maintained at least 10F below saturation temperature.

MILLSTONE - UNIT 3 3/4 4-2 Amendment No. fp,197 0776

REACTOR COOLANT SYSTEM HOT SHUTDOWN LIMITING CONDITION FOR OPERATION 3.4.1.3 Either:*,**

a. With the Control Rod Drive System capable of rod withdrawal, at least two RCS loops shall be OPERABLE and in operation, or

b. With the Control Rod Drive System not capable of rod withdrawal, at least I two loops consisting of any combination of RCS loops and residual heat removal (RHR) loops shall be OPERABLE, and at least one of these loops shall be in operation. For RCS loop(s) to be OPERABLE, at least one reactor coolant pump (RCP) shall be in operation.

APPLICABILITY: MODE 4.

ACTION:

a. With less than the above required loops OPERABLE, immediately initiate corrective action to return the required loops to OPERABLE status as soon as possible; if the remaining OPERABLE loop is an RHR loop, be in COLD SHUTDOWN within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br />.

b. With less than the above required reactor coolant loops in operation and I the Control Rod Drive System is capable of rod withdrawal, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> open the Reactor Trip System breakers.

c. With no loop in operation, suspend all operations involving a reduction in boron concentration of the Reactor Coolant System and immediately initiate corrective action to return the required loop to operation.

• All reactor coolant pumps and RHR pumps may be deenergized for up to 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> provided: (1) no operations are permitted that would cause dilution of the Reactor Coolant System boron concentration, and (2)core outlet temperature is maintained at least 10OF below saturation temperature.

• • The first reactor coolant pump shall not be started when any RCS loop wide range cold leg temperature is < 226F unless:

a. Two pressurizer PORVs are in service to meet the cold overpressure protection requirements of Technical Specification 3.4.9.3 and the secondary side water temperature of each steam generator is < 506F above each RCS cold leg temperature; OR

b. The secondary side water temperature of each steam generator is at or below each RCS cold leg temperature.

This restriction only applies to RCS loops and associated components that are not isolated from the reactor vessel.

MILLSTONE - UNIT 3 0776 3/4 4-3 Amendment No. 7, 7Y7,197

REACTOR COOLANT SYSTEM HOT SHUTDOWN SURVEILLANCE REQUIREMENTS 4.4.1.3.1 The required pump(s), if not in operation, shall be determined OPERABLE once per 7 days by verifying correct breaker alignments and indicated power availability.

4.4.1.3.2 The required steam generator(s) shall be determined OPERABLE by verifying secondary side water level to be greater than or equal to 17% at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />.

4.4.1.3.3 The required loop(s) shall be verified in operation and circulating reactor coolant at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />.

MILLSTONE - UNIT 3 3/4 4-4 Amendment No. 7f,197 0775

REACTOR COOLANT SYSTEM COLD SHUTDOWN - LOOPS FILLED LIMITING CONDITION FOR OPERATION 3.4.1.4.1 At least one residual heat removal (RHR) loop shall be OPERABLE and in operation*, and either:

a. One additional RHR loop shall be OPERABLE**, or

b. The secondary side water level of at least two steam generators shall be greater than 17%.

APPLICABILITY: MODE 5 with at least two reactor coolant loops filled***.

• a. The RHR pump may be deenergized for up to 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> provided: (1) no operations are permitted that would cause dilution of the Reactor Coolant System boron concentration, and (2) core outlet temperature is maintained at least 10OF below saturation temperature.

b. All RHR loops may be removed from operation during a planned heatup to MODE 4 when at least one RCS loop is OPERABLE and in operation and when two additional steam generators are OPERABLE as required by LCO 3.4.1.4.1.b.

• • One RHR loop may be inoperable for up to 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> for surveillance testing provided the other RHR loop is OPERABLE and in operation.

• • • The first reactor coolant pump shall not be started when:

a. Any RCS loop wide range cold leg temperature is > 150F unless:

1. Two pressurizer PORVs are in service to meet the cold overpressure protection requirements of Technical Specification 3.4.9.3 and the secondary side water temperature of each steam generator is < 50*F above each RCS cold leg temperature; OR

2. The secondary side water temperature of each steam generator is at or below each RCS cold leg temperature.

b. All RCS loop wide range cold leg temperatures are < 150F unless the secondary side water temperature of each steam generator is < 50F above each RCS cold leg temperature.

This restriction only applies to RCS loops and associated components that are not isolated from the reactor vessel.

3/4 4-5 Amendment No. g7y, 197 0775

REACTOR COOLANT SYSTEM COLD SHUTDOWN - LOOPS FILLED LIMITING CONDITION FOR OPERATION ACTION:

a. With less than the required RHR loop(s) OPERABLE or with less than the required steam generator water level, immediately initiate corrective action to return the inoperable RHR loop to OPERABLE status or restore the required steam generator water level as soon as possible.

b. With no RHR loop in operation, suspend all operations involving a reduction in boron concentration of the Reactor Coolant System and immediately initiate corrective action to return the required RHR loop to operation.

SURVEILLANCE REQUIREMENTS 4.4.1.4.1.1 The secondary side water level of at least two steam generators when required shall be determined to be within limits at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />.

4.4.1.4.1.2 At least one RHR loop shall be determined to be in operation and circulating reactor coolant at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />.

4.4.1.4.1.3 The required pump, if not in operation, shall be determined OPERABLE once per 7 days by verifying correct breaker alignment and indicated power availability. I MILLSTONE - UNIT 3 3/4 4-5a Amendment No. J07, 197 0776

REACTOR COOLANT SYSTEM COLD SHUTDOWN - LOOPS NOT FILLED LIMITING CONDITION FOR OPERATION 3.4.1.4.2 Two residual heat removal (RHR) loops shall be OPERABLE* and at least one RHR loop shall be in operation.**

APPLICABILITY: MODE 5 with less than two reactor coolant loops filled***.

ACTION:

a. With less than the above required RHR loops OPERABLE, immediately initiate corrective action to return the required RHR loops to OPERABLE status as soon as possible.

b. With no RHR loop in operation, suspend all operations involving a reduction in boron concentration of the Reactor Coolant System and immediately initiate corrective action to return the required RHR loop to operation.

• One RHR loop may be inoperable for up to 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> for surveillance testing provided the other RHR loop is OPERABLE and in operation.

• • The RHR pump may be deenergized for up to 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> provided: (1) no opera-tions are permitted that would cause dilution of the Reactor Coolant System boron concentration, and (2) core outlet temperature is maintained at least 10F below saturation temperature.

• • • The first reactor coolant pump shall not be started when:

a. Any RCS loop wide range cold leg temperature is > 150F unless:

1. Two pressurizer PORVs are in service to meet the cold overpressure protection requirements of Technical Specification 3.4.9.3 and the secondary side water temperature of each steam generator is < 500F above each RCS cold leg temperature; OR

2. The secondary side water temperature of each steam generator is at or below each RCS cold leg temperature.

b. All RCS loop wide range cold leg temperatures are < 150'F unless the secondary side water temperature of each steam generator is < 50F above each RCS cold leg temperature.

This restriction only applies to RCS loops and associated components that are not isolated from the reactor vessel.

MILLSTONE - UNIT 3 3/4 4-6 Amendment No. fps ii. 07.197 0775

REACTOR COOLANT SYSTEM COLD SHUTDOWN - LOOPS NOT FILLED SURVEILLANCE REQUIREMENTS 4.4.1.4.2.1 The required pump, if not in operation, shall be determined OPERABLE once per 7 days by verifying correct breaker alignment and indicated power availability.

4.4.1.4.2.2 At least one RHR loop shall be determined to be in operation and circulating reactor coolant at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />.

MILLSTONE - UNIT 3 3/4 4-6a Amendment No. 0F7'197 0776

REACTOR COOLANT SYSTEM LOOP STOP VALVES I ITMTITNGCOlNMlTTTON FlR OPFRATTAN 3.4.1.5 Each RCS loop stop valve shall be open and the power removed from the valve operator. I APPLICABILITY: MODES 1, 2, 3 and 4.

ACTION:

a. With power available to one or more loop stop valve operators, remove power from the loop stop valve operators within 30 minutes or be in HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

b.c" With one or more RCS loop stop valves closed, maintain the valve(s) closed and be in HOT STANDBY within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and COLD SHUTDOWN within the next 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

SURVEILLANCE REQUIREMENTS 4.4.1.5 Verify each RCS loop stop valve is open and the power removed from the valve operator at least once per 31 days. I All required actions of Action Statement 3.4.1.5.b shall be completed whenever this action is entered.

MILLSTONE - UNIT 3 3/4 4-7 Amendment No. 217 0982

REACTOR COOLANT SYSTEM ISOLATED LOOP STARTUP LIMITING CONDITION FOR OPERATION 3.4.1.6 A reactor coolant loop shall remain isolated with power removed from the associated RCS loop stop valve operators until:

a. The temperature at the cold leg of the isolated loop is within 200 F of the highest cold leg temperature of the operating loops, and I

b. The boron concentration of the isolated loop is greater than or equal to the boron concentration required by Specifications 3.1.1.1.2 or 3.1.1.2 for MODE 5 or Specification 3.9.1.1 for MODE 6. I APPLICABILITY: MODES 5 and 6.

ACTION:

a. With the requirements of the above specification not satisfied, do not open the isolated loop stop valves.

SURVEILLANCE REQUIREMENTS 4.4.1.6.1 The isolated loop cold leg temperature shall be determined to be within 20'F of the highest cold leg temperature of the operating loops within 30 minutes prior to opening the cold leg stop valve.

4.4.1.6.2 The isolated loop boron concentration shall be determined to be greater than or equal to the boron concentration required by Specifications 3.1.1.1.2 or 3.1.1.2 for MODE 5 or Specification 3.9.1.1 for MODE 6 within 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> prior to opening the hot or cold leg stop valve.

I MILLSTONE - UNIT 3 3/4 4-8 Amendment No. 7!, F7, PO, XF7,202 0776 Jleg O. KV

REACTOR COOLANT SYSTEM 314.4.2 SAFETY VALVES I

LIMITING CONDITION FOR OPERATION 3.4.2 All pressurizer Code safety valves shall be OPERABLE with a lift I setting* of 2500 psia +/- 3%.**

APPLICABILITY: MODES 1, 2, and 3, MODE 4 with all RCS cold leg temperatures > 226*F. I ACTION:

With one pressurizer Code safety valve inoperable, restore the inoperable valve to OPERABLE status within 15 minutes. If the inoperable valve is not restored to OPERABLE status within 15 minutes, or if two or more.pressurizer .Code safety valves are inoperable, be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in HOT SHUTDOWN with any RCS cold leg temperature < 226'F within the following 24 hours1 days <br />0.143 weeks <br />0.0329 months <br />.

SURVEILLANCE REQUIREMENTS 4.4.2 No additional Surveillance Requirements other than those required by I Specification 4.0.5.

• *The lift setting pressure shall correspond to ambient conditions of the valve at nominal operating temperature and pressure.

• • The lift setting shall be within i 1% following pressurizer Code safety valve testing.

MILLSTONE - UNIT 3 3/4 4-9 Amendment No. Ipf, 197 0776

This Page Intentionally Left Blank MILLSTONE - UNIT 3 3/4 4-10 Amendment No. lPi,197 0776

REACTOR COOLANT SYSTEM 3/4.4.3 PRESSURIZER STARTUP AND POWER OPERATION LIMITING CONDITION FOR OPERATION 3.4.3.1 The pressurizer shall be OPERABLE with:

a. at least two groups of pressurizer heaters, each having a capacity of I at least 175 kW; and

b. water level maintained at programmed level +/-6% of full scale (Figure 3.4-5).

APPLICABILITY: MODES 1 and 2.

ACTION:

a. With only one group of pressurizer heaters OPERABLE, restore at least two groups to OPERABLE status within 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />.

b. With pressurizer water level outside the parameters described in Figure 3.4-5, within 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> restore programmed level to within +/- 6%

of full scale, or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />.

c. With the pressurizer otherwise inoperable, be in at least HOT STANDBY with the Reactor Trip System breakers open within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />.

SURVEILLANCE REQUIREMENTS 4.4.3.1.1 The pressurizer water level shall be verified to be within programmed level +/- 6% of full scale at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />.

4.4.3.1.2 The capacity of each of the above required groups of pressurizer heaters shall be verified by energizing the heaters and measuring circuit I current at least once each refueling interval.

MILLSTONE - UNIT 3 3/4 4-11 Amendment No. l0, If?, 210 0812 AUG 2 6 2k2

PRESSURIZER LEVEL CONTROL 70 - - -

A --a-A-. -. .. .. . ..

-Programmed Level plus T Percent ofFulliScale / - -------

50 ---------

-- ,--------/-- -w 4-a- -t-a  : .Programmed Level Minus-W --- i-- a 6 Percent of Full Scale 3------$- ee---4-------

-orame

--- ---- - . .. ~..

PormmdL.'4 ---- -

20--------0V - lA r--- a - a---- - -- - -

I 4 a

.A - . a -0 a a - .

a- a- a-- ----- --- a---- ----

LUa-a---a I- -- -- --- -- -- - a--

-- -- Ia-- - -- - - a-- - a- - a--

a a a a a a 10 -------

4- -

20 - -- --- --- ---

a---a--a-a-- --

a---

- a--

a---

3 a--

4a-aa-a a

---

---- *--- ---------------------- ~- .---------- i----------

551 557 562 567 572 577 582 587.1 591.1 T (AVG)

FIGURE 3.4-5 ILSTONE'- UN-IT 3' 3/4 4,1.a. *. . * . mtdnt.to.160

REACTOR COOLANT SYSTEM HOT STANDBY LIMITING CONDITION FOR OPERATION 3.4.3.2 The pressurizer shall be OPERABLE with:

a. at least two groups of pressurizer heaters, each having a capacity of at least 175 kW; and

b. water level less than or equal to 89% of full scale.

APPLICABILITY: MODE 3 ACTION:

a. With only one group of pressurizer heaters OPERABLE, restore at least I two groups to OPERABLE status within 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> of being declared inoperable, or be in HOT SHUTDOWN within the following 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />.

b. With the pressurizer otherwise inoperable, be in HOT SHUTDOWN within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />.

SURVEILLANCE REQUIREMENTS 4.4.3.2.1 The pressurizer water level shall be determined to be less than or equal to 89% of full scale at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />.

4.4.3.2.2 The capacity of each of the above required groups of pressurizer heaters shall be verified by energizing the heaters and measuring circuit current at least once each refueling interval.

MILLSTONE - UNIT 3 3/4 4-lib Amendment No. Ifo, 210 0813 AUG 26 MM2

REACTOR COOLANT SYSTEM 314.4.4 RELIEF VALVES LIMITING CONDITION FOR OPERATION 3.4.4. Both power-operated relief valves (PORVs) and their associated block valves shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTION:

a. With one or both PORV(s) inoperable because of excessive seat-leakage, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> either restore the PORV(s) to OPERABLE status or close the associated block valve(s) with power maintained to the block valve(s); otherwise, be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in HOT SHUTDOWN within the following 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />.

b. With one PORV inoperable due to causes other than excessive seat leakage, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> either restore the PORY to OPERABLE status or close the associated block valve and remove power from the block valve; restore the PORV to OPERABLE status within the following 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> or be in HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in HOT SHUTDOWN within the following 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />.

c. With both PORYs inoperable due to causes other than excessive seat leakage, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> either restore at least one PORV to OPERABLE status or close its associated block valve and remove power from the block valve and be in HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in HOT SHUTDOWN within the following 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />.

d. With one or both block valve(s) inoperable, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> restore the block valve(sy to OPERABLE status, or place its associated PORV(s) control switch to "CLOSE." Restore at least one block valve to OPERABLE status within the next hour if both block valves are inoperable; restore any remaining inoperable block valve to operable status within 72 hours3 days <br />0.429 weeks <br />0.0986 months <br />; otherwise, be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in HOT SHUTDOWN within the following 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />.

e. Entry into an OPERATIONAL MODE is permitted while subject to these ACTION requirements.

MILLSTONE - UNIT 3 3/4 4-12 Amendment No. ,7, FF, 161 0587

REACTOR COOLANT SYSTEM RELIEF VALVES SURVEILLANCE REQUIREMENTS 4.4.4.1 In addition to the requirements of Specification 4.0.5, each PORV shall be demonstrated OPERABLE by:

a. Performance of a CHANNEL CALIBRATION at least once per 24 months; and

b. Operating the valve through one complete cycle of full travel during MODES 3 or 4 at least once per 24 months; and

c. Performance of an ANALOG CHANNEL OPERATIONAL TEST on the PORV high pressurizer pressure actuation channels, but excluding valve operation, at least once each quarter; and

d. Verify the PORV high pressure automatic opening function is enabled at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />.

4.4.4.2 Each block valve shall be demonstrated OPERABLE at least once per 92 days by operating the valve through one complete cycle of full travel unless the block valve is closed with power removed in order to meet the requirements of ACTION b.

or c. in Specification 3.4.4.

MILLSTONE - UNIT 3 3/4 4-13 Amendment No. g?, 117, Xfj, 0814 70f, 210 AUG 2 6 2w2

REACTOR COOLANT SYSTEM 3/4.4.5 STEAM GENERATORS LIMITING CONDITION FOR OPERATION 3.4.5 Each steam generator associated with an operating RCS loop shall be OPERABLE.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTION:

With one or more steam generators associated with an operating RCS loop inoperable, restore the inoperable generator(s) to OPERABLE status prior to increasing Tavg above 200'F.

SURVEILLANCE REQUIREMENTS 4.4.5.0 Each steam generator shall be demonstrated OPERABLE by performance of the following augmented inservice inspection program and the requirements of Specification 4.0.5.

4.4.5.1 Steam Generator Sample Selection and Inspection - Each steam generator shall be determined OPERABLE during shutdown by selecting and inspecting at least the minimum number of steam generators specified in Table 4.4-1.

4.4.5.2 Steam Generator Tube Sample Selection and Inspection - The steam generator tube minimum sample size, inspection result classification, and the corresponding action required shall be as specified in Table 4.4-2. The inservice inspection of steam generator tubes shall be performed at the fre-quencies specified in Specification 4.4.5.3 and the inspected tubes shall be verified acceptable per the acceptance criteria of Specification 4.4.5.4. The tubes selected for each inservice inspection shall include at least 3% of the total number of tubes in all steam generators; the tubes selected for these inspections shall be selected on a random basis except:

a. Where experience in similar plants with similar water chemistry indicates critical areas to be inspected, then at least 50% of the tubes inspected shall be from these critical areas;

b. The first sample of tubes selected for each inservice inspection (subsequent to the preservice inspection) of each steam generator shall include:

MILLSTONE - UNIT 3 3/4 4-14

REACTOR COOLANT SYSTEM STEAM GENERATORS SURVEILLANCE REQUIREMENTS (Continued)

1) All nonplugged tubes that previously had detectable wall penetrations (greater than 20%),

2) Tubes in those areas where experience has indicated potential problems, and

3) A tube inspection (pursuant to Specification 4.4.5.4a.8) shall be performed on each selected tube. If any selected tube does not permit the passage of the eddy current probe for a tube inspection, this shall be recorded and an adjacent tube shall be selected and subjected to a tube inspection.

c. The tubes selected as the second and third samples (if required by Table 4.4-2) during each inservice inspection may be subjected to a partial tube inspection provided:

1) The tubes selected for these samples include the tubes from those areas of the tube sheet array where tubes with imperfections were previously found, and

2) The inspections include those portions of the tubes where imperfections were previously found.

The results of each sample inspection shall be classified into one of the following three categories:

Category Inspection Results C-1 Less than 5% of the total tubes inspected are degraded tubes and none of the inspected tubes are defective.

C-2 One or more tubes, but not more than 1% of the total tubes inspected are defective, or between 5% and 10% of the total tubes inspected are degraded tubes.

C-3 More than 10% of the total tubes inspected are degraded tubes or more than 1% of the inspected tubes are defective.

Note: In all inspections, previously degraded tubes must exhibit significant (greater than 10%) further wall penetrations to be included in the above percentage calculations.

MILLSTONE - UNIT 3 3/4 4-15

REACTOR COOLANT SYSTEM STEAM GENERATORS SURVEILLANCE REQUIREMENTS (Continued) 4.4.5.3 Inspection Frequencies - The above required inservice inspections of steam generator tubes shall be performed at the following frequencies:

a. Inservice inspections shall be performed at intervals of not less than 12 nor more than 24 calendar months* after the previous inspection. If two consecutive inspections, not including the preservice inspection, result in all inspection results falling into the C-1 category or if two consecutive inspections demonstrate that previously observed degradation

- has not continued and no additional degradation has occurred, the inspection interval may be extended to a maximum of once per 40 months;

b. If the results of the inservice inspection of a steam generator conducted in accordance with Table 4.4-2 at 40-month intervals fall in Category C-3, the inspection frequency shall be increased to at least once per 20 months. The increase in inspection frequency shall apply until the subsequent inspections satisfy the criteria of Specification 4.4.5.3a.;

the interval may then be extended to a maximum of once per 40 months; and

c. Additional, unscheduled inservice inspections shall be performed on each steam generator in accordance with the first sample inspection specified in Table 4.4-2 during the shutdown subsequent to any of the following conditions:

1) Primary-to-secondary tubes leak (not including leaks originating from tube-to-tube sheet welds) in excess of the limits of Specification 3.4.6.2, or

2) A seismic occurrence greater than the Operating Basis Earthquake, or

3) A loss-of-coolant accident requiring actuation of the Engineered Safety Features, or

4) A main steam line or feedwater line break.

• Except the surveillance related to Steam Generator Inspection, due no later than September 24, 1998, may be deferred until the next refueling outage or no later than July 1, 1999, whichever is earlier.

MILLSTONE - UNIT 3 3/4 4-16 Amendment No. Al, $A,Z;0,163 0596

REACTOR COOLANT SYSTEM STEAM GENERATOR SURVEILLANCE REQUIREMENTS (Continued) 4.4.5.4 Acceptance Criteria

a. As used in this specification:

1) Imperfection means an exception to the dimensions, finish, or contour of a tube from that required by fabrication drawings or specifications. Eddy-current testing indications below 20% of the nominal tube wall thickness, if detectable, may be considered as imperfections;

2) Degradation means a service-induced cracking, wastage, wear, or general corrosion occurring on either inside or outside of a tube;

3) Degraded Tube means a tube containing imperfections greater than or equal to 20% of the nominal wall thickness caused by degradation;

4)  % Dearadation means the percentage of the tube wall thickness affected or removed by degradation;

5) Defect means an imperfection of such severity that it exceeds the plugging limit. A tube containing a defect is defective;

6) Plugging Limit means the imperfection depth at or beyond which the tube shall be removed from service and is equal to 40%

of the nominal tube wall thickness;

7) Unserviceable describes the condition of a tube if it leaks or contains a defect large enough to affect its structural integ-rity in the event of an Operating Basis Earthquake, a loss-of-coolant accident, or a steam line or feedwater line break as specified in Specification 4.4.5.3c., above;

8) Tube Inspection means an inspection of the steam generator tube from the point of entry (hot leg side) completely around the U-bend to the top support of the cold leg; or an inspection from the point of entry (Hot Leg or Cold Leg Side) completely around the U-bend to the opposite tube end.

MILLSTONE - UNIT 3 3/4 4-17 Amendment No. 41 SEP 1I 1989 I

REACTOR COOLANT SYSTEM STEAM GENERATOR SURVEILLANCE REQUIREMENTS (Continued)

9) Preservice Inspection means an inspection of the full length of each tube in each steam generator performed by eddy current techniques prior to service to establish a baseline condition of the tubing. This inspection shall be performed prior to initial POWER OPERATION using the equipment and techniques expected to be used during subsequent inservice inspections.

b. The steam generator shall be determined OPERABLE after completing the corresponding actions (plug all tubes exceeding the plugging limit and all tubes containing through-wall cracks) required by Table 4.4-2.

4.4.5.5 Reports

a. Within 15 days following the completion of each inservice inspection of steam generator tubes, the number of tubes plugged in each steam generator shall be reported to the Commission in a Special Report pursuant to Specification 6.9.2;

b. The complete results of the steam generator tube inservice inspection shall be submitted to the Commission in a Special Report pursuant to Specification 6.9.2 within 12 months following the completion of the inspection. This Special Report shall include:

1) Number and extent of tubes inspected,

2) Location and percent of wall-thickness penetration for each indication of an imperfection, and

3) Identification of tubes plugged.

c. Results of steam generator tube inspections which fall into Category C-3 shall be reported in a Special Report to the Commission pursuant to Specification 6.9.2 within 30 days and prior to resumption of plant operation. This report shall provide a description of investi-gations conducted to determine cause of the tube degradation and corrective measures taken to prevent recurrence.

MILLSTONE - UNIT 3 3/4 4-18

F-4 I-I-

--I TABLE 4.4-1 MINIMUM NUMBER OF STEAM GENERATORS TO BE

'-4

--I INSPECTED DURING INSERVICE INSPECTION WA Preservice Inspectioin No Yes No. of Steam Generators per Unit Two Threou Two Three Four First Inservice Inspection All One Two Two Second & Subsequent Inservice Inspections One1 Onel One 2 One3 l

I-Pn t0 TABLE NOTATIONS

1. The inservice inspection may be limited to one steam generator on a rotating schedule encompassing 3 N % of the tubes (where N is the number of steam generators in the plant) if the results of the first or previous inspections indicate that all steam generators are performing in a like manner. Note that under some circumstances, the operating conditions in one or more steam generators may be found to be more severe than those in other steam generators. Under such circum-stances the sample sequence shall be modified to inspect the most severe conditions.

2. The other steam generator not inspected during the first inservice inspection shall be inspected. The third and subsequent inspections should follow the instructions described in 1 above.

3. Each of the other two steam generators not inspected during the first inservice inspections shall be inspected during the second and third inspections. The fourth and subsequent inspections shall follow the instructions described in 1 above.

I-i TABLE 4.4-2 I-CA

-4 STEAM GENERATOR TUBE INSPECTION C) 1ST SAMPLE INSPECTION 2ND SAMPLE INSPECTION 3RD SAMPLE INSPECTION g-~4

--I Sample Size Result Action Required Result Action Required Result Action Required LA A minimum of C-1 None N. A. N. A. N. A. N.A.

S Tubes per S. G.

C-2 Plug defective tubes C-1 None N. A. N. A.

and inspect additional Plug defective tubes C-1 None 2S tubes in this S. G. C-2 and inspect additional C-2 Plug defective tubes

. G. Perform action for w~ C-3 C-3 result of first sample r'~)

0~ Perform action for C-3 C-3 result of first N. A. N. A.

, _ sample C-3 Inspect all tubes in All other this S. G., plug de- S. G.s are None N. A. N. A.

fective tubes and C-1 inspect 2S tubes in Some S. G.s Perform action for N. A. N. A.

each other S. G. C-2 but no C-2 result of second additional sample Notificatior to NRC S. G. are pursuant to § 50.72 C-3 (b)(2) of 10 CFR Additional Inspect all tubes in Part 50 S. G. is C-3 each S. G. and plug defective tubes.

Notification to N RC N. A. N. A.

pursuant to § 50.72 (b)(2) of 10 CFR Part 50 S = 3 N% Where N is the number of steam generators in the unit, and n is the number of steam generators inspected n during an inspection

REAL UR iCLrf i 3/4.4.6 REACTOR COOLANT SYSTEM LEAKAGE LEAKAGE DETECTION SYSTEMS LIMITING CONDITION FOR OPERATION __

3.4.6.1 The following Reactor Coolant System Leakage Detec on ;sfte-m shail be OPERABLE:

a. Either the Containment Atmosphere Gasec;_ ,sDar- ate Radioactivity Monitoring System. and

b. The Containment Drain Sump Level or Pumped Capacity Monitoring System APPLICABILITY: MODES 1, 2, 3, and 4.

ACTION:

a. With both the Containment Atmosphere Gaseous and Particulate Rauioactivity Monitors INOPERABLE. operation may continue for up to 30 days provided the Containment Drain Sump Level or Pumped Capacity Monitoring System is OPERABLE and gaseous grab samples of the containment atmosphere are obtained at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> and analyzed for gross noble gas activity within the subsequent 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br />:

otherwise, be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

b. With the Containment Drain Sump Level or Pumped Capacity Monitoring System INOPERABLE, operation may continue for up to 30 days provided either the Containment Atmosphere Gaseous or Particulate Radioactivity Monitoring System is OPERABLE; otherwise, be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN withi.. the followng 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

SURVEILLANCE REQUIREMENTS 4.4.6.1 The Leakage Detection Systems shall be demonstrated OPERABLE by:

a. Containment Atmosphere Gaseous and Particulate Radioactivity Monitoring Systems-performance of CHANNEL CHECK, CHANNEL CALIBRATION, and ANALOG CHANNEL OPERATIONAL TEST at the frequencies specified in Table 4.3-3, and

b. Containment Drain Sump Level and Pumped Capacity Monitoring System-performance of CHANNEL CALIBRATION at least once per 24 months.

MILLSTONE - UNIT 3 3/4 4-21 Amendment No. 17, 7i, lop, 177, 206 0847

REACTOR COOLANT SYSTEM OPERATIONAL LEAKAGE LIMITING CONDITION FOR OPERATION 3.4.6.2 Reactor Coolant System leakage shall be limited to:

a. No PRESSURE BOUNDARY LEAKAGE,

b. 1 gpm UNIDENTIFIED LEAKAGE,

c. 1 gpm total reactor-to-secondary leakage through all steam generators not isolated from the Reactor Coolant System and 500 gallons per day through any one steam generator not isolated from the Reactor Coolant System,

d. 10 gpm IDENTIFIED LEAKAGE from the Reactor Coolant System,

e. 40 gpm CONTROLLED LEAKAGE at a Reactor Coolant System pressure of 2250 + 20 psia, and f.* 0.5 gpm leakage per nominal inch of valve size up to a maximum of 5 gpm at a Reactor Coolant System pressure of 2250 + 20 psia from any Reactor Coolant System Pressure Isolation Valve specified in Table 3.4-1.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTION:

a. With any PRESSURE BOUNDARY LEAKAGE, be in at least HOT STANDBY within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

b. With any Reactor Coolant System leakage greater than any one of the above limits, excluding PRESSURE BOUNDARY LEAKAGE and leakage from Reactor Coolant System Pressure Isolation Valves, reduce the leakage rate to within limits within 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

c. With any Reactor Coolant System Pressure Isolation Valve leakage greater than the above limit, isolate the high pressure portion of the affected system from the low pressure portion within 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> by use of at least two closed manual or deactivated automatic valves, or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

• This requirement does not apply to Pressure Isolation Valves in the Residual Heat Removal flow path when in, or during the transition to or from, the shutdown cooling mode of operation.

MILLSTONE - UNIT 3 3/4 4-22 Amendment No. 2Q9 0819 AUG 2 1 2

REACTOR COOLANT SYSTEM OPERATIONAL LEAKAGE SURVEILLANCE REQUIREMENTS 4.4.6.2.1 Reactor Coolant System leakages shall be demonstrated to be within each of the above limits by:

a. Deleted

b. Deleted I

c. Measurement of the CONTROLLED LEAKAGE to the reactor coolant pump seals when the Reactor Coolant System pressure is 2250 + 20 psia at least once per 31 days with the modulating valve fully open. The provisions of Specification 4.0.4 are not applicable for entry into MODE 3 or 4;

d. Performance of a Reactor Coolant System water inventory balance within 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> of achieving steady state operation, and at least once per 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> thereafter during steady state operation. The provisions of Specification 4.0.4 are not applicable for entry into MODE 3 or 4; and

e. Monitoring the Reactor Head Flange Leakoff System at least once per 24 hours1 days <br />0.143 weeks <br />0.0329 months <br />.

4.4.6.2.2" 1I2' Each Reactor Coolant System Pressure Isolation Valve specified in Table 3.4-1 shall be demonstrated OPERABLE by verifying leakage to be within its limit:

a. At least once per 24 months,

b. Prior to entering MODE 2 whenever the plant has been in COLD SHUTDOWN for 7 days or more and if leakage testing has not been performed in the previous 9 months, i

c. Deleted

d. Within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> following valve actuation due to automatic or manual action or flow through the valve, and

e. When tested pursuant to Specification 4.0.5.

'"t The provisions of Specification 4.0.4 are not applicable for entry into MODE 3 or 4.

(2) This surveillance is not required to be performed on Reactor Coolant System Pressure Isolation Valves located in the RHR flow path when in, or during the transition to or from, the shutdown cooling mode of operation.

MILLSTONE - UNIT 3 3/4 4-23 Amendment No. y0, J3, 7X70 0941 A, 209 AUG 21 22

TABLE 3.4-1 REACTOR COOLANT SYSTEM PRESSURE ISOLATION VALVES VALVE NUMBER FUNCTION 3-SIL-V15 SI Tank 1A Discharge Isolation Valve 3-SIL-V17 SI Tank 1B Discharge Isolation Valve 3-SIL-V19 SI Tank iC Discharge Isolation Valve 3-SIL-V21 SI Tank ID Discharge Isolation Valve 3-SIL-V26 RHR/SI to RCS Loop 2, Hot Leg 3-SIL-V27 SIH to RCS Loop 2, Hot Leg 3-SIL-V28 RHR/SI to RCS Loop 4, Hot Leg 3-SIL-V29 SIH to RCS Loop 4, Hot Leg 3-SIL-V984 RHR/SI to RCS Loop 4, Cold Leg 3-SIL-V985 RHR/SI to RCS Loop 3, Cold Leg 3-SIL-V986 RHR/SI to RCS Loop 2, Cold Leg 3-SIL-V987 RHR/SI to RCS Loop 1, Cold Leg 3-SIH-V5 SIH to RCS Cold Legs 3-SIH-V110 SIH to RCS Loop 1, Hot Leg 3-SIH-V112 SIH to RCS Loop 3, Hot Leg 3-RCS-V26 SIH to RCS Loop 1, Hot Leg 3-RCS-V29 SIH to RCS Loop 1, Cold Leg 3-RCS-V30 SIL to RCS Loop 1, Cold Leg 3-RCS-V69 RHR/SI to RCS Loop 2, Hot Leg 3-RCS-V70 SIH to RCS Loop 2, Cold Leg 3-RCS-V71 SIL to RCS Loop 2, Cold Leg 3-RCS-V102 SIH to RCS Loop 3, Hot Leg 3-RCS-V106 SIH to RCS Loop 3, Cold Leg 3-RCS-V.07 SIL to RCS Loop 3, Cold Leg 3-RCS-VJ42 RHR/SI to RCS Loop 4, Hot Leg 3-RCS-V145 SIH to RCS Loop 4, Cold Leg 3-RCS-V146 SIL to RCS Loop 4, Cold Leg 3-RHS-MV8701C RCS Loop 1, Hot Leg to RHR 3-RHS-MV8702C RCS Loop 4, Hot Leg to RHR 3-RHS-MV8701A RCS Loop 1, Hot Leg to RHR 3-RHS-MV8702B RCS Loop 4, Hot Leg to RHR MILLSTONE - UNIT 3 3f4 4-24

This page intenionally left blank MILLSTONE - UNIT 3 3/4 4-25 Amendment No. 204 0788

This page intentionally left blank MILLSTONE - UNIT 3 3/4 4-26 Amendment No. 204 0788

This page intentionally left blank MILLSTONE - UNIT 3 3/4 4-27 Amendment No.204 1 0788

REACTOR COOLANT SYSTEM 3/4.4.8 SPECIFIC ACTIVITY LIMITING CONDITION FOR OPERATION 3.4.8 The specific activity of the reactor coolant shall be limited to:

a. Less than or equal to 1 microCurie per gram DOSE EQUIVALENT I-131, and

b. Less than or equal to 100/E microCuries per gram of gross radioactivity.

APPLICABILITY: MODES 1, 2, 3, 4, and 5.

ACTION:

MODES 1, 2 and 3*:

a. With the specific activity of the reactor coolant greater than 1 microCurie per gram DOSE EQUIVALENT I-131 for more than 48 hours2 days <br />0.286 weeks <br />0.0658 months <br /> during one continuous time interval, or exceeding the limit line shown on Figure 3.4-1, be in at least HOT STANDBY with T less than 500'F within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />; and avg

b. With the specific activity of the reactor coolant greater than 100E microCuries per gram, be in at least HOT STANDBY with T less than 500'F within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />. avg MODES 1, 2, 3, 4, and 5:

With the specific activity of the reactor coolant greater than 1 microCurie per gram DOSE EQUIVALENT I-131 or greater than 100/E micro-Curies per gram, perform the sampling and analysis requirements of Item 4.a) of Table 4.4-4 until the specific activity of the reactor coolant is restored to within its limits.

• With Tavg greater than or equal to 500'F.

MILLSTONE - UNIT 3 3/4 4-28

REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS 4.4.8 The specific activity of the reactor coolant shall be determined to be within the limits by performance of the sampling and analysis program of Table 4.4-4.

MILLSTONE - UNIT 3 3/4 4-29

E a

L lz 0-.

250 S.-

B-.

s-i S.-

C.,

• -6 200 a-1

'IL I-150 z

-J 0

0 0~ 100 6-I 0-zw 50

-J b-s Iii V) 0 0 20 30 40 50 60 70 80 90 100 0

PERCENT OF RATED THERMAL POWER FIGURE 3.4-1 DOSE EQUIVALENT 1-131 REACTOR COOLANT SPECIFIC ACTIVITY LIMIT VERSUS PERCENT OF RATED THERMAL POWER WITH THE REACTOR COOLANT SPECIFIC ACTIVIY >1 uCT/groam DOSE EQUIVALENT 1-131 MILLSTONE - UNIT 3 3/4 4-30 Amendment No. 60 l .' 1 1 i91

TABLE 4.4-4 1-4 REACTOR COOLANT SPECIFIC ACTIVITY SAMPLE I-I- AND ANALYSIS PROGRAM

--I 0

TYPE OF MEASUREMENT SAMPLE AND ANALYSIS MODES IN WHICH SAMPLE m AND ANALYSIS FREQUENCY AND ANALYSIS REQUIRED

-I

1. Gross Radioactivity At least once per 72 hours3 days <br />0.429 weeks <br />0.0986 months <br />. 1, 2, 3, 4 3

LA)

Determination

2. Isotopic Analysis for DOSE EQUIVA- 1 per 14 days. 1 LENT I-131 Concentration

3. Radiochemical for E Determination* 1 per 6 months** 1

4. Isotopic Analysis for Iodine a) Once per 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />, 1#, 2#, 3#, 4#, 5#

Including I-131, I-133, and I-135 whenever the specific activity exceeds I pCi/gram DOSE EQUIVALENT I-131 or 100/E pCi/gram of tLA gross radioactivity, and CA, b) One sample between 2 1, 2, 3 and 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> following a THERMAL POWER change exceeding 15%

of the RATED THERMAL POWER within a 1-hour period.

TAELE 4.4-4 (Continued)

TABLE NOTATIONS

• A radiochemical analysis for E shall consist of the quantitative measurement of the specific activity for each radionuclide, except for radionuclides with half-lives less than 10 minutes and all radioiodines, which is identified in the reactor coolant. The specific activities for these individual radionuclides shall be used in the determination of E for the reactor coolant sample. Determination of the contributors to E shall be based upon those energy peaks identifiable with a 95% confidence level.

• • Sample to be taken after a minimum of 2 EFPD and 20 days of POWER OPERATION have elapsed since reactor was last subcritical for 48 hours2 days <br />0.286 weeks <br />0.0658 months <br /> or longer. The provisions of Specification 4.0.4 are not applicable. I

1. Until the specific activity of the Reactor Coolant System is restored within its limits.

MILLSTONE - UNIT 3 3/4 4-32 AMENDMENT NO. 55 f- ' 9 1990

REACTOR COOLANT SYSTEM 3/4.4.9 PRESSURE/TEMPERATURE LIMITS LIMITING CONDITION FOR OPERATION 3.4.9.1 Reactor Coolant System (except the pressurizer) temperature, pressure, and heatup and cooldown rates uf "erritic materials shall be limited in accordance with the limits shown on Figures 3.4-2 and 3.4-3. In addition, a maximum of one reactor coolant pump can be in operation when the lowest unisolated Reattor Coolant System loop wide range cold leg temperature is

< 160'F.

APPLICABILITY: At all times.

ACTION:

a. With any of the above limits exceeded in MODES 1, 2, 3, or 4, perform the following:

1. Restore the temperature and/or pressure to within limit within 30 minutes.

AND

2. Perform an engineering evaluation to determine the effects of the out of limit condition on the structural integrity of the Reactor Coolant System and determine that the Reactor Coolant System remains acceptable for continued operation within 72 hours3 days <br />0.429 weeks <br />0.0986 months <br />. Otherwise, be in at least MODE 3 within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in MODE 5 with RCS pressure less than 500 psia within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

b. With any of the above limits exceeded in other than MODES 1, 2, 3, or 4, perform the following:

1. Immediately initiate action to restore the temperature and/or pressure to within limit.

AND

2. Perform an engineering evaluation to determine the effects of the out of limit condition on the structural integrity of the Reactor Coolant System and determine that the Reactor Coolant System is acceptable for continued operation prior to entering MODE 4.

SURVEILLANCE REQUIREMENTS 4.4.9.1.1 The Reactor Coolant System temperature and pressure shall be determined to be within the limits at least once per 30 minutes during system heatup and cooldown operations, and during the one-hour period prior to and during inservice leak and hydrostatic testing operations.

4.4.9.1.2 DELETED MILLSTONE - UNIT 3 3/4 4-33 Amendment No. I7n, 177, 214 0873

Millstone 3 Reactor Coolant System Heatup Limitations for Fluence up to 1.97E+19 n/cm (32 EFPY) 2500 II 2000 1500 z

ra,

-S (I)

In IL a-a, 0

C 1000 500 0

0 50 100 150 200 250 300 350 400 Indicated Cold Leg Temeprature (F)

FIGURE 3.4-2 MILLSTONE - UNIT 3 3/4 4-34 Amendment No. #R, R7, 197 0777

Millstone 3 Reactor Coolant System Cooldown Limitations for Fluence up to 1.97E+19 n/cm (32 EFPY) 2500

[Cooldown Limit 2000 T it 1500 Unacceptable Operation-0.

40 a) 1000 Cooldown At A Maximum of 80 F]

In Any 1-Hour Period To 1600F,1 Then At A Maximum of 20 0 F In Any 1-Hour Period Below 1600F]

2:

.~-

buu W : 1--:1 ,. 1 l -v . i. !-.* f i -5 . i M. I . i .4 _9 i !1:477A7:* : I vI1 I 2I-1I11i I .4 - i 4 4 I

F, . I..... - .._- . _.. ; i .;

I I.7 i

Cooldown At A Maximum of 800 F

_ I

., ;'. ;4.1..

'i,

..J

..1, .

z;

- i.

t:,,

- - - -A - I - -

m

'.t I7-H;.,;

I - I - - - In Any 1-Hour Period To 160'F, i

!i

.. 1.-EIIJ-d---II

- - I- A l I ------

I-II,.1 Then At A Maximum of 400 F In Any 1-Hour Period Below 1600 F ill I I

0 0 s0

~1IR~H 100 150 200 250 300 350

,III

-A 400 Indicated Coid Leg Temeprature (F)

FIGURE 3.4-3 MILLSTONE - UNIT 3 3/4 3443 4-35 Amendment No. M, fl7' 197 0777

THIS PAGE INTENTIONALLY LEFT BLANK MILLSTONE - UNIT 3 3/4 4-36 Amendment No. fy, JM7, }il 214 0874

This page intentionally left blank MILLSTONE - UNIT 3 3/4 4-37 Amendment No. 1y7, 204 0789

REACTOR COOLANT SYSTEM OVERPRESSURE PROTECTION SYSTEMS LIMITING CONDITION FOR OPERATION 3.4.9.3 Cold Overpressure Protection shall be OPERABLE with a maximum of one centrifugal charging pump* and no Safety Injection pumps capable of injecting into the Reactor Coolant System (RCS) and one of the following pressure relief capabilities:

1. One power operated relief valve (PORV) with a nominal lift setting established in Figure 3.4-4a and one PORV with a nominal lift setting established in Figure 3.4-4b with no more than one isolated RCS loop, or

2. Two residual heat removal (RHR) suction relief valves with setpoints

> 426.8 psig and < 453.2 psig, or

3. One PORV with a nominal lift setting established in Figure 3.4-4a or Figure 3.4-4b with no more than one isolated RCS loop and one RHR suction relief valve with a setpoint > 426.8 psig and < 453.2 psig, or

4. RCS depressurized with an RCS vent of > 2.0 square inches.

APPLICABILITY: MODE 4 when any RCS cold leg temperature is < 226F, MODE 5, and MODE 6 when the head is on the reactor vessel.

ACTION:

a. With two or more centrifugal charging pumps capable of injecting into the RCS, immediately initiate action to establish that a maximum of one centrifugal charging pump is capable of injecting into the RCS.

b. With any Safety Injection pump capable of injecting into the RCS, immediately initiate action to establish that no Safety Injection pumps are capable of injecting into the RCS.

c. With one required relief valve inoperable in MODE 4, restore the required relief valve to OPERABLE status within 7 days, or depressurize and vent the RCS through at least a 2.0 square inch vent within the next 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />.

• Two centrifugal charging pumps may be capable of injecting into the RCS for less than one hour, during pump swap operations. However, at no time will two charging pumps be simultaneously out of pull-to-lock during pump swap operations.

MILLSTONE - UNIT 3 3/4 4-38 Amendment No. IF, Y7, F, 1 , IF7,197 0778

REACTOR COOLANT SYSTEM OVERPRESSURE PROTECTION SYSTEMS LIMITING CONDITION FOR OPERATION

d. With one required relief valve inoperable in MODE 5 or 6, restore the required relief valve to OPERABLE status within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br />, or depressurize the RCS and establish an RCS vent of > 2.0 square inches within the next 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />. I

e. With two required relief valves inoperable, depressurize the RCS and establish an RCS vent of > 2.0 square inches within 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />.

f. In the event the PORVs, the RHR suction relief valves, or the RCS vent are used to mitigate an RCS pressure transient, a Special Report shall be prepared and submitted to the Commission pursuant to Specification 6.9.2 within 30 days. The report shall describe the circumstances initiating the transient, the effect of the PORVs, the RHR suction relief valves, or RCS vent on the transient, and any corrective action necessary to prevent recurrence.

9. Entry into an OPERATIONAL MODE is permitted while subject to these ACTION requirements.

MILLSTONE - UNIT 3 3/4 4-38a Amendment No. IF, 7, FF, Add 0778 t797 197

REACTOR COOLANT S(STEM OVERPRESSURE PROTECTION SYSTEM SURVEILLANCE REQUIREMENTS 4.4.9.3.1 Demonstrate that each ed P{qu P.B LPEP.BE b:

a. Performance of an HhE L 'P n-A' HANbLi ,R KE? ,r PORV .scOiVt io channel, but excluding a ie 'opeition. .-,hhin31 dai. pricr ncere rinn a condition in ,nich 0r V TR i uire O(EPA6LE andJa- C3;-i bce per 31 days thereafter ihEin h, 'JRv . requi red JP[P*ABLE

b. Performance of a CHANINIEL CALIERA-i9jli on^,The POR'V actuato!n channel at least once per 24 months: and

c. Verifying the PORV block valve is open and the PORV Cold Overpressure Protection System (COPPS) is armed at least once per 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> when the PORV is being used for overpressure protection.

4.4.9.3.2 Demonstrate that each required RHR Suction relief valve is OPERABLE by:

a. Verifying the isolation valves between the RCS and each required RHR suction relief valve are open at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />: and

b. Testing pursuant to Specification 4.0.5.

4.4.9.3.3 When complying with 3.4.9.3.4, verify that the RCS is vented through a vent pathway > 2.0 square inches at least once pLr 31 days for a passive vent path and at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> for unlocked open vent valves.

4.4.9.3.4 Verify that no Safety Injection pumps are capable of injecting into the RCS at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />.

4.4.9.3.5 Verify that a maximum of one centrifugal charging pump is capable of injecting into the RCS at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />.

MILLSTONE - UNIT 3 3/4 4-39 Amendment No. 7p, 9p, 10p, M, 0849 DE7. 7l7, 206

High Setpoint PORY Curve For the Cold Overpressure Protection System U

0 c

>' 400 a:

0

-c E

z 0 50 100 150 200 250 Auctioneered Low Measure RCS Temperature (F)

FIGURE 3.4-4a MILLSTONE - UNIT 3 3/4 4-40 Amendment No. iP, W7, 78 197

Low Setpoint PORV Curve For the Cold Overpressure Protection System 800

1. f I 700 600 7-i

Ai r: 7.

500 U

e7t Z 0.

AJ 4 47t; U) 400 a: It 0a-777

-Z S

E 0

Z U... I Y1U.1 1("A) 4*.

44 4 .~ -~ + . I ...-..

+-.

, ,. -,I :q, -.1:-;

I.

-t:,,

-,?.- -

J, j ; -, ., .1-t-;; 11.Z,.

'M, ,.-

-V i i "..,

- I;,,I- ,.;.

. 'n 7-,""'

. I ': 1 1 I . s . .. ,

il T 7, 7 200 100 0

0 50 100 150 200 250 Auctioneered Low Measure RCS Temperature (F)

FIGURE 3.4-4b MILLSTONE - UNIT 3 3/4 4-41 Amendment No. P?, 7y7, 0778 197

This page intentionally left blank MILLSTONE - UNIT 3 3/4 4-42 Amendment No. P7, jyy 204 0790 I

This page intentionally left blank MILLSTONE - UNIT 3 3/4 4-43 Anendment No. PF, 199, 204 0790

This page intentionally left blank M0LLSTONE - UNIT 3 3/4 4-43a Amendment No. 79, FY, 711, 204 0790

3/4.5 EMERGENCY CORE COOLING SYSTEMS 3/4.5.1 ACCUMULATORS LIMITING CONDITION FOR OPERATION 3.5.1 Each Reactor Coolant System (RCS) accumulator shall be OPERABLE with:

a. The isolation valve open and power removed,

b. A contained borated water volume of between 6618 and 7030 gallons,

c. A boron concentration of between 2600 and 2900 ppm, and

d. A nitrogen cover-pressure of between 636 and 694 psia.

APPLICABILITY: MODES 1, 2, and 3*.

ACTION:

a. With one accumulator inoperable, except as a result of a closed isolation valve, restore the inoperable accumulator to OPERABLE status within 8 hours0.333 days <br />0.0476 weeks <br />0.011 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and reduce pressurizer pressure to less than 1000 psig within the following 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />.

b. With one accumulator inoperable due to the isolation valve being closed, either immediately open the! isolation valve or be in at least HOT STANDBY within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> anmd reduce pressurizer pressure to less than 1000 pslg within the followingz 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />.

SURVEILLANCE REQUIREMENTS 4.5.1 Each accumulator shall be demonstrated OPERABLE: I

a. At least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> by:

1) Verifying that the contained borated water volume and nitrogen cover-pressure in the tanks are within their limits, and I

2) Verifying that each accumulator isolation valve is open.

b. At least once per 31 days and within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> after each solution volume increase of greater than or equal to 1% of tank volume by verifying the boron surveillance is not the RWST.

concentration of the accumulator solution. This required when the volume increase makeup source is I

• Pressurizer pressure above 1000 psig.

MILLSTONE - UNIT 3 3/4 5-1 Amendment No. fl, 17g fp. 100 Oam JAU V3 195

EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

c. At least once per 31 days when the RCS pressure is above 1000 psig by verifying that the associated circuit breakers are locked in a deenergized position or removed. I

'-\ 4 An; -9 * , , ., I i-,

EMERGENCY CORE COOLING SYSTEMS 3/4.5.2 ECCS SUBSYSTEMS - T. GREATER THAN OR EQUAL TO 350"F LIKITING CONDITION FOR OPERATION 3.5.2 Two independent Emergency Core Cooling System (ECCS) subsystems shall be OPERABLE with each subsystem comprised of:

a. One OPERABLE centrifugal charging pump,

b. One OPERABLE Safety Injection pump,

c. One OPERABLE RHR heat exchanger,*

d. One OPERABLE RHR pump,*

e. One OPERABLE containment recirculation heat exchanger,

f. One OPERABLE containment recirculation pump, and

g. An OPERABLE flow path capable of taking suction from the refueling water storage tank on a Safety Injection signal and capable of automat-ically stopping the RHR pump and being manually realigned to transfer suction to the containment sump during the recirculation phase of operation.

APPLICABILITY: MODES 1, 2, and 3.

ACTION:

a. With one ECCS subsystem inoperable, restore the inoperable subsystem to OPERABLE status within 72 hours3 days <br />0.429 weeks <br />0.0986 months <br />* or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in HOT SHUTDOWN within the following 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />.

b. In the event the ECCS is actuated and Injects water into the Reactor Coolant System, a Special Report shall be prepared and submitted to the Commission pursuant to Specification 6.9.2 within 90 days describ-ing the circumstances of the actuation and the total accumulated actuation cycles to date. The current value of the usage factor for each affected Safety Injection nozzle shall be provided in this Special Report whenever its value exceeds 0.70.

• The allowable outage time for each RHR pump/RHR heat exchanger may be extended to 120 hours5 days <br />0.714 weeks <br />0.164 months <br /> for the purpose of pump modification to change mechanical seal and other related modifications. This exception may only be used one time per RHR pump/RHR heat exchanger and is not valid after April 30, 1995.

MILLSTONE - UNIT 3 3/4 5-3 Amendment No. 103 0an rfEB 9 1995

SURVEILLANCE REQUIREMENTS 4.5.2 Each ECCS subsystem shai De ie .orl ,>ia ecu GUcr+rrEt;:

a. At least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> by -,  ; sing that 'the roller

.~ ng va3lv ;s are in the indicated positions ,:h po.:-, to 'ne valve operators removed:

Valve Number Valv e Fu,-,cior, Salve Position 3SIH*MV8806 P'WST Supply to -P OPEN 3SIH*MV8802A SI Pump to Hot g Inje cion CLOSEC 3SIH*MV8802B Si Pump B to Hot Leg Injection CLOSED 3SIH*MV8835 SI Cold Leg Master Isolation OPEN 3SIH*MV8813 SI Pump Master Mirniflow OPEN Isolation 3SIL*MV8840 RHR to Hot Leg Injection CLOSED 3SIL*MV8809A RHR Pump A to Cold Leg OPEN In jection 3SIL*MV8809B RHR Pump B to Cold Leg OPEN Injection

b. At least once per 31 days by:

1) Verifying that the ECCS piping. except for the operating centrifugal charging pump(s) and associated piping. the RSS pump. the RSS heat exchanger and associated piping. is full of water, and

2) Verifying that each valve (manual, power-operated, or automatic) in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position.

By a . sual inspection which verifies triat no loose debris (rags, trash, clothing, etc.) is present in the containment which could be transported to the containment sump and cause restriction of the pump suctions during LOCA conditions. This visual inspection shall be performed:

1) For all accessible areas of the containment prior to establish-ing CONTAINMENT INTEGRITY, and

2) At least once daily of the areas affected (during each day) within containment by containment entry and during the final entry when CONTAINMENT INTEGRITY is established.

d. At least once per 24 months by:

1) Verifying automatic interlock action of the RHR System from the Reactor Coolant System by ensuring that with a simulated signal greater than or equal to 412.5 psia the interlocks prevent the valves from being opened.

MILLSTONE - UNIT 3 3/4 5-4 Amendment No. 9p, i, X00, l9', 797, 0851 19 ,206

SURVEILLANCE REQUIREMENTS (Continued)

2) A visual inspection of th Containment sump and .'erifyiing that the subsystem suction inkt -e not. restricted by rebris an]

that the sump components Krash racks. screens. etc.) show no evidence of structural di.isZs- .,- abnormal corrosion.

e. At least once per 24 -onths by:

1) Verifying that each automat'c valve in the flos path actuates to its correct position on a Safety Injection actuation test signal.

and

2) Verifying that each of the following pumps start automatically upon receipt of a Safety Injection actuation test signal:

a) Centrifugal charging pump.

b) Safetv Injection pump. and c) RHR pump.

3) Verifying that the Residual Heat Removal pumps stop automatically upon receipt of a Low-Low RWST Level test signal.

f. By verifying that each of the following pump's developed head at tne test flow point is greater than or equal to the required developed head when tested pursuant to Specification 4.0.5:

1) Centrifugal charging pump

2) Safety Injection pump

3) RHR pump

4) Containment recirculation pump

g. By verifying the correct position of each electrical and/or mechanical position stop for the following ECCS throttle valves:

1) Within 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> following completion of each valve stroking operation or maintenance on the valve when the ECCS subsystems are required to be OPERABLE, and

2) At least once per 24 months.

ECCS Throttle Valves Valve Number Valve Number 3SIH*V6 3SIH*V25 3SIH*V7 3SIH*V27 MILLSTONE - UNIT 3 3/4 5-5 Amendment No.  ?, gg, jg, 206 085 I

EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREHENTS (Continued)

ECCS Throttle Valves Valve Number Valve Number 3SIH*V8 3S IH*VI07 3SIH*V9 3SIH*V108 3SIH*V21 3SIH*V109 3SIH*V23 3SIH*V 111

h. By performing a flow balance test following completion of modifications to the ECCS subsystems that alter the subsystem flow characteristics and verifying that: -

I) For centrifugal charging pump lines, with a single pump running:

a) The sum of the injection line flow rates, excluding the highest flow rate, is greater than or equal to 310.5 gpm, I and b) The total pump flow rate is less than or equal to 560 gpm.

2) For Safety Injection pump lines, with a single pump running:

a) The sum of the injection line flow rates, excluding the highest flow rate, is greater than or equal to 423.4 gpm, and b) The total pump flow rate is less than or equal to 675 I

gpm.

3) For RHR pump lines, with a single pump running, the sum of the injection line flow rates is greater than or equal to 3976 gpm.

MILLSTONE - UNIT 3 3/4 S-6 Amendment No. FP, ;f,- 155 0568

• " - i,

EMERGENCY CORE COOLING SYSTEMS 3/4.5.3 ECCS SUBSYSTEMS - T,, LESS THAN 350F LIMITING CONDITION FOR OPERATION 3.5.3 As a minimum, one ECCS subsystem comprised of the following shall be OPERABLE:

a. One OPERABLE centrifugal charging pump,

b. One OPERABLE RHR heat exchanger,

c. One OPERABLE RHR pump,

d. One OPERABLE containment recirculation heat exchanger,

e. One OPERABLE containment recirculation pump, and

f. An OPERABLE flow path which, with manual realignment of valves, is capable of discharging to the RCS, taking suction from the refueling water storage tank, and transferring suction to the containment sump during the recirculation phase of operation.

APPLICABILIJTY: MODE 4.

a. With no ECCS subsystem OPERABLE because of the inoperability of the centrifugal charging pump, the containment recirculation pump, the containment recirculation heat exchanger, the flow path from the refueling water storage tank, or the flow path capable of taking suction from the containment sump, restore at least one ECCS sub-system to OPERABLE status within I hour or be in COLD SHUTDOWN within the next 20 hours0.833 days <br />0.119 weeks <br />0.0274 months <br />.

b. With no ECCS subsystem OPERABLE because of the inoperability of either the residual heat removal heat exchanger or RHR pump, restore at least one ECCS subsystem to OPERABLE status or maintain the Reac-tor Coolant System T., less than 350'F by use of alternate heat removal methods. -

c. In the event the ECCS Is actuated and Injects water into the Reactor Coolant System, a Special Report shall be prepared and submitted to the Commission pursuant to Specification 6.9.2 within 90 days describ-ing the circumstances of the actuation and the total accumulated actuation cycles to date. The current value of the usage factor for each affected Safety Injection nozzle shall be provided in this Special Report whenever its value exceeds 0.70.

MILLSTONE - UNIT 3 3/4 5-7 Amendment No. 157 0527 f23 '3

EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS 4.5.3.1 The ECCS subsystem shall be demonstrated OPERABLE per the applicable requirements of Specification 4.5.2, with the exception that valves may be out of alignment but capable of being manually realigned. I MILLSTONE - UNIT 3 3/4 5-8 Amendment No. 157 0527

EMERGENCY CORE COOLING SYSTEMS 3/4.5.4 REFUELING WATER STORAGE TANK LIMITING CONDITION FOR OPERATION 3.5.4 The refueling water storage tank (RWST) shall be OPERABLE with:

a. A contained borated water volume between 1,166,000 and 1,207,000 gallons,

b. A boron concentration between 2700 and 2900 ppm of boron,

c. A minimum solution temperature of 40'F, and

d. A maximum solution temperature of 50F.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTION With the RWST Inoperable, restore the tank to OPERABLE status within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or be in at least HOT STANDBY within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

SURVEILLANCE REQUIREMENTS 4.5.4 The RWST shall be demonstrated OPERABLE:

a. At least once per 7 days by:

1) Verifying the contained borated water volume in the tank, and

2) Verifying the boron concentration of the water.

b. At least once per 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> by verifying the RWST temperature.

MILLSTONE - UNIT 3 3/4 5-9 Amendment No. ;I ,60 00233 -r

EMERGENCY CORE COOLING SYSTEMS 3/4.5.5 pH TRISODIUM PHOSPHATE STORAGE BASKETS LIMITING CONDITION FOR OPERATION 3.5.5 The trisodium phosphate '-L!- -,

Jo znvsrate 5 Baskets shall -e OPERABLE.

APPLICABILITY: INODES 1. 2. 4 fanti ACTION:

With the TSP Storage Baskets inoperable, restore the system. TSP Storage Baskets to OPERABLE status within 7 days or be in at least HOT STANDBY :.-ithin the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in HOT SHUTDOWN the following 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />.

SURVEILLANCE REQUIREMENTS 4.5.5 The TSP Storage Baskets shall be demonstrated OPERABLE at least once per 24 months by verifying that a minimum total of 974 cubic feet of TSP is contained in the TSP Storage Baskets.

MILLSTONE UNIT NO. 3 3/4 5-10 Amendment No. jlu,_ 206 0852

3/4.6 CONTAINMENT SYSTEMS 314.6.1 PRIMARY CONTAINMENT CONTAINMENT INTEGRITY LIMITING CONDITION FOR OPERATION 3.6.1.1 Primary CONTAINMENT INTEGRITY shall be maintained.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTION:

Without primary CONTAINMENT INTEGRITY, restore CONTAINMENT INTEGRITY within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

SURVEILLANCE REQUIREMENTS 4.6.1.1 Primary CONTAINMENT INTEGRITY shall be demonstrated:

a. At least once per 31 days by verifying that all penetrations' not capable of being closed by OPERABLE containment automatic isolation valves, 2R and required to be closed during accident conditions are closed by valves, blind flanges, or deactivated automatic valves secured in their positions, 3? except for valves that are open under administrative control as permitted by Specification 3.6.3; and

b. By verifying that each containment air lock is in compliance with the requirements of Specification 3.6.1.3.

c. Deleted Except valves, blind flanges, and deactivated automatic valves which are located inside the containment and are locked, sealed, or otherwise secured in the closed position. These penetrations shall be verified closed during each COLD SHUTDOWN except that such verification need not be performed more often than once per 92 days.

(2) In MODE 4, the requirement for an OPERABLE containment isolation valve system is satisfied by use of the containment isolation actuation pushbuttons.

(3) Isolation devices in high radiation areas may be verified by use of administrative means.

MILLSTONE - UNIT 3 3/4 6-1 Amendment No. 97, 79f, 70,216 0937

CONTAINMENT SYSTEMS CONTAINMENT LEAKAGE LIMITING CONDITION FOR OPERATION 3.6.1.2 Containment leakage rates shall be limited in accordance with the Containment Leakage Rate Testing Program.

I APPLICABILITY: MODES 1, 2, 3, and 4.

ACTION:

With the containment leakage rates exceeding the limits, restore the leakage rates to within limits within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or be In at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

SURVEILLANCE REQUIREMENTS 4.6.1.2 The containment leakage rates shall be demonstrated in conformance with the criteria specified in the Containment Leakage Rate Testing Program.

MILLSTONE - UNIT 3 3/4 6-2 Amendment No. Ph, F7, pi, A1i, 0708 JZ0, IO, 186

This page intentionally left blank MILLSTONE - UNIT 3 3/4 6-3 Amendment No. pi, 7P, J; PP. I, 186 0708

This page Intentionally left blank.

MILLSTONE - UNIT 3 3/4 6-4 Amendment No. Ap, AZ 89, 0202 Ld.7 e 1 :".1

CONTAINMENT SYSTEMS CONTAINMENT AIR LOCKS LIMITING CONDITION FOR OPERATION 3.6.1.3 The containment air lock shall be OPERABLE with:

a. Both doors closed except when the air lock is being used for normal transit entry and exit through the containment. then at least one air lock door shall be closed, and

b. An overall air lock leakage rate in accordance with the Containment Leakage Rate Testing Program.

APPLICABILITY: MODES 1. 2, 3. and 4.

ACTION:

NOTE [

Entry and exit through the containment air lock doors is permitted to perform repairs on the affected air lock components.

Il'

a. With only one containment air lock door inoperable:

1. Verify the OPERABLE air lock door is closed within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and either restore the inoperable air lock door to OPERABLE status within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> or lock the OPERABLE air lock door closed.

2. Operation may then continue provided that the OPERABLE air lock door is verified to be locked closed at least once per 31 days.

3. Otherwise. he in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />, and.

4. Entry into an OPERATIONAL MODE is permitted while subject to these ACTION requirements.

b. With only the containment air lock interlock mechanism inoperable, verify an OPERABLE air lock door is closed within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and lock an OPERABLE air lock door closed within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br />. Verify an OPERABLE air lock door is locked closed at least once per 31 days thereafter.

Otherwise, be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />. (Entry into and exit from containment is permissible under the control of a dedicated individual).

MILLSTONE - UNIT 3 3/4 6-5 Amendment No. U7, As, M 0801 70, 205

CONTAINMENT SYSTEMS CONTAINMENT AIR LOCKS LIMITING CONDITION FOR OPERATION Continued

c. With the containment air lock inoperable, except as specified in ACTLOII

a. or ACTION b. above. immediately initiate action to evaluate overall containment leakage rate per Specification 3.6.1.2 and verify an air lock door is closed within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. Restore the air lock to OPERABLE status within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br />. Otherwise. be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDO!ItJ within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

SURVEILLANCE REQUIREMENTS t1.. i. } .3 Each containment air lock shall be demonstrated OPERABLE:

a. By verifying leakage results in accordance with the Containment Leakage Rate Testing Program. Containment air lock leakage test results shall e- evaluated against the leakage limits of Technical Specific-+ :

3.6.1.2. (An inoperable air lock door does not invalidate the previ :

successful performance of the overall air lock leakage test).

b. Deleted

c. At least once per 24 months by verifying that only one door in each air I lock can be opened at a time.

MILLSTONE - UNIT 3 3/4 6-6 Amendment No. 0-, 179, M,2Q5 0801

CONTAINMENT SYSTEMS CONTAINMENT PRESSURE LIMITING CONDITION FOR OPERATION 3.6.1.4 Primary containment pressure shall be maintained greater than or equal to 10.6 psia and less than or equal to 14.0 psia.

APPLICABILITY: MODES 1, 2, 3, and 4.

1 ACTION:

With the containment pressure less than 10.6 psia or greater than 14.0 psia, restore the containment pressure to within the limits within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

I SURVEILLANCE REOUIREMENTS 4.6.1.4 The primary containment pressure shall be determined to be within the limits at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />.

I Amendment No. 59 MILLSTONE - UNIT 3 3/4 6-7 , 3 i Y}

This Page Intentionally Left Blank Amendment No. 59 MILLSTONE - UNIT 3 3/4 6-8 J ,i , 5la

CONTAINMENT SYSTEMS AIR TEMPERATURE LIMITING CONDITION FOR OPERATION 3.6.1.5 Primary containment average air temperature shall be maintained greater than or equal to 80'F and less than or equal to 120 0F.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTION:

With the containment average air temperature less than 80'F or greater than 120 0F, restore the average air temperature to within the limit within 8 hours0.333 days <br />0.0476 weeks <br />0.011 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

SURVEILLANCE REQUIREMENTS 4.6.1.5 The primary containment average air temperature shall be the arith-metical average of the temperatures at the following locations and shall be determined at least once per 24 hours1 days <br />0.143 weeks <br />0.0329 months <br />:

Location

a. 94 ft elevation, E outside crane wall

b. 86 ft elevation, NW outside crane wall

c. 75 ft elevation, W Steam Generator platform

d. 75 ft elevation, E Steam Generator platform

e. 45 ft elevation, Pressurizer cubicle, crane wall MILLSTONE - UNIT 3 3/4 6-9

CONTAINMENT SYSTEMS CONTAINMENT STRUCTURAL INTEGRITY LIMITING CONDITION FOR OPERATION 3.6.1.6 The structural integrity of the containment shall be maintained at a level consistent with the acceptance criteria in Specification 4.6.1.6.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTION:

With the structural integrity of the containment not conforming to the above requirements, restore the structural integrity to within the limits within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

SURVEILLANCE REQUIREMENTS 4.6.1.6.1 Containment Surfaces The structural integrity of the exposed acces-sible interior and exterior surfaces of the containment, including the liner plate, shall be determined at the frequency specified in the Containment Leakage l Rate Testing Program.

4.6.1.6.2 Reports Any abnormal degradation of the containment structure de-tected during the above required inspections shall be reported to the Commis-sion in a Special Report pursuant to Specification 6.9.2 within 15 days. This report shall include a description of the condition of the concrete, the inspec-tion procedure, the tolerances on cracking, and the corrective actions taken.

MILLSTONE - UNIT 3 3/4 6-10 Amendment No. 186 0710

CONTAINMENT SYSTEMS CONTAINMENT VENTILATION SYSTEM LIMITING CONDITION FOR OPERATION 3.6.1.7 Each containment purge supply and exhaust isolation valve shall be OPERABLE and each 42-inch containment shutdown purge supply and exhaust isola-tion valve shall be closed and locked closed.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTION:

a. With a 42-inch containment purge supply and/or exhaust isolation valve open or not locked closed, close and/or lock close that valve or isolate the penetration(s) within 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />, otherwise be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

SURVEILLANCE REQUIREMENTS 4.6.1.7.1 The containment purge supply and exhaust isolation valves shall be verified to be locked closed and closed at least once per 31 days.

I MILLSTONE - UNIT 3 3/4 6-11 Amendment No. 5

CONTAINMENT SYSTEMS 3/4.6.2 DEPRESSURIZATION AND COOLING SYSTEMS CONTAINMENT QUENCH SPRAY SYSTEM LIMITING CONDITION FOR OPERATION 3.6.2.1 Two independent Containment Quench Spray subsystems shall be OPERABLE.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTION:

With one Containment Quench Spray subsystem inoperable, restore the inoperable system to OPERABLE status within 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

SURVEILLANCE REQUIREMENTS 4.6.2.1 Each Containment Quench Spray subsystem shall be demonstrated OPERABLE:

a. At least once per 31 days, by:

1) Verifying that each valve (manual, power operated, or automatic) in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position; and

2) Verifying the temperature of the borated water in the refueling water storage tank is between 40'F and 500 F.

b. By verifying that each pump's developed head at the test flow point is greater than or equal to the required developed head when tested pursuant to Specification 4.0.5;

c. At least once per 24 months, by:

I) Verifying that each automatic valve in the flow path actuates to its correct position on a CDA test signal, and

2) Verifying that each spray pump starts automatically on a CDA test signal.

d. By verifying each spray nozzle is unobstructed following maintenance that could cause nozzle blockage.

MILLSTONE - UNIT 3 3/4 6-12 Amendment No. -, 4G, 4IW, 4-a, 45, 4-4,2G6, 222

CONTAINMENT SYSTEMS RECIRCULATION SPRAY SYSTEM LIMITING CONDITION FOR OPERATION 3.6.2.2 Two independent Recirculation Spray Systems shall be OPERABLE.

APPLICABILITY: MODES 1, 2,3, and 4.

ACTION:

With one Recirculation Spray System inoperable, restore the inoperable system to OPERABLE status within 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />; restore the inoperable Recirculation Spray System to OPERABLE status within the next 48 hours2 days <br />0.286 weeks <br />0.0658 months <br /> or be in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

SURVEILLANCE REQUIREMENTS 4.6.2.2 Each Recirculation Spray System shall be demonstrated OPERABLE:

a. At least once per 31 days by verifying that each valve (manual, power-operated, or automatic) in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position;

b. By verifying that each pump's developed head at the test flow point is greater than or equal to the required developed head when tested pursuant to Specification 4.0.5;

c. At least once per 24 months by verifying that on a CDA test signal, each recirculation spray pump starts automatically after a 660 +20 second delay;

d. At least once per 24 months, by verifying that each automatic valve in the flow path actuates to its correct position on a CDA test signal; and

e. By verifying each spray nozzle is unobstructed following maintenance that could cause nozzle blockage. I MILLSTONE - UNIT 3 3/4 6-13 Amendment No. -, 4iG, .A, I-.5, 474,24, 222

Intentionally Left Blank MILLSTONE - UNIT 3 3/4 6-14 Aendment No. ;t, fps 0304 115 MAY 2 6 1S95

CONTAINMENT SYSTEMS 3/4.6.3 - CONTAINMENT ISOLATION VALVES LIMITING CONDITION FOR OPERATION 3.6.3 The containment isolation valves shall be OPERABLE.'" 121 APPLICABILITY: MODES 1, 2, 3, and 4.

ACTION:

With one or more of the isolation valve(s) inoperable, maintain at least one isolation barrier OPERABLE in the affected penetration(s), and:

a. Restore the inoperable valve(s) to OPERABLE status within 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />, or

b. Isolate the affected penetration(s) within 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> by use of deactivated automatic valve(s) secured in the isolation position(s), or

c. Isolate the affected penetration(s) within 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> by use of closed manual valve(s) or blind flange(s); or

d. Isolate the affected penetration that has only one containment isolation valve and a closed system within 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> by use of at least one closed and deactivated automatic valve, closed manual valve, or blind flange; or

e. Be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

SURVEILLANCE REQUIREMENTS 4.6.3.1 DELETED 4.6.3.2 Each isolation valve shall be demonstrated OPERABLE during the COLD SHUTDOWN or REFUELING MODE at least once per 24 months by:

a. Verifying that on a Phase "A" Isolation test signal, each Phase "A" isolation valve actuates to its isolation position,

b. Verifying that on a Phase "B" Isolation test signal, each Phase "B" isolation valve actuates to its isolation position, and

c. Verifying that on a Containment High Radiation test signal, each purge supply and exhaust isolation valve actuates to its isolation position.

4.6.3.3 The isolation time of each power-operated or automatic valve shall be determined to be within its limit when tested pursuant to Specification 4.0.5.

The provisions of this Specification are not applicable for main steam line isolation valves. However, provisions of Specification 3.7.1.5 are applicable for main steam line isolation valves.

(2) Containment isolation valves may be opened on an intermittent basis under administrative controls.

MILLSTONE - UNIT 3 3/4 6-15 Amendment No. 1g, 97, P7, 0991 0, J77, ;If, 700, 79F, 216

THIS PAGE INTNIONALLY LEFT BLANK MIILLSTONED -UNIT 3 3/4 6-16 Amendment No. 4-, a, i, 44G, 224

THIS PAGE IMENTIONALLY LEFT BLANK MILLSTONE - UNIT 3 3/4 6-17 Amendment No. 4-7, 6,400, 427, , 2224

CONTAINMENT SYSTEMS 3/4.6.5 SUBATMOSPHERIC PRESSURE CONTROL SYSTEM STEAM JET AIR EJECTOR LIMITING CONDITION FOR OPERATION 3.6.5.1 The inside and outside isolation valves in the steam jet air ejector suction line shall be closed.

APPLICABILfIT: MODES I, 2, 3, and 4.

ACTION:

With the inside or outside isolation valves in the steam jet air ejector suction line not closed, restore the valve to the closed position within I hour or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

SURVEILLANCE REQUIREMENTS 4.6.5.1.1 The steam jet air ejector suction line outside isolation valve shall be determined to be in the closed position by a visual inspection prior to increasing the Reactor Coolant System temperature above 200F and at least once per 31 days thereafter.

4.6.5.1.2 The steam Jet air ejector suction line inside isolation valve shall be determined to be locked in the closed position by a visual inspection prior to Increasing the Reactor Coolant System temperature above 2000F.

Amendment No.100 MILLSTONE - UNIT 3 GM5 3/4 6-18 3

3?

I

CONTAINMENT SYSTEMS 3/4.6.6 SECONDARY CONTAINMENT SUPPLEMENTARY LEAK COLLECTION AND RELEASE SYSTEM LIMITING CONDITION FOR OPERATION

.3.6.6.1 Two independent SuppF zer r a,-; l I - ,e-ria shall be OPERABLE wiith each *o,- T 1)r u

a. one OPERABLE filter and fan. arn

b. one OPERABLE Auxiliary Buildinq Fi-ler System as defined in Specification 3.7.9.

APPLICABILITY: rMODES 1. 2. 3. and 4.

ACTION:

With one Supplementary Leak Collection and Release System inoperable, restore the inoperable system to OPERABLE status within 7 days or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

SURVEILLANCE REQUIREMENTS 4.6.6.1 Each Supplementary Leak Collection and Release System shall be demon-strated OPERABLE:

a. At least once per 31 da: s on a STAGGERE. TEST BASIS by initiating, from the control room, flow through the HEPA filters and charcoal adsorbers and verifying a system flow rate of 7600 cfm to 9800 cfm and that the system operates for at least 10 continuous hours with the heaters operating.

b. At least once per 24 months or (1) after any structural maintenance on the HEPA filter or charcoal adsorber housings, or (2) following painting, fire., or chemical release in any ventilation zone communi-cating with the system by:

1) Verifying that the system satisfies the in-place penetration and bypass leakage testing acceptance criteria of less than 0.05% and uses the test procedure guidance in Regulatory Posi-tions C.5.a, C.5.c, and C.5.d of Regulatory Guide 1.52, Revi-sion 2, March 1978,* and the system flow rate is 7600 cfm to 9800 cfm; MILLSTONE - UNIT 3 3/4 6-19 Amendment No. Z. 7, i7, 0855 lop, Xg1, 206

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

2) Verifying. ;-ichin a', 'aaf!r  :-ova, Fhat a laboratory analysis of 3 :veoresenta ,e OS-bF sample obtained in accord-ance with Pcs;ion r'eoulatorv of Regulatory Guide 1.52.

I.5)o 8-is Pevi sion 2. ,!arcr. 13787 w e nethyi iodide penetration less than or equal to 2.- .ihen tested in ac-ordance with ASTH 03803-89 at a temperature 3f 30<C (36'F" and a relative humidit;r of 70%: and

3) Verifying a system flow rate of 7600 cfm to 9800 cfm during svste-operation when tested in accordance with ANSI N510-1980.

c. After every 720 hours30 days <br />4.286 weeks <br />0.986 months <br /> of charcoal adsorber operation. by verifying.

within 31 days after removal that a laboratory analysis of a repre-sentative carbon sample obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.59. Revision 2, March 1978.* shows the methyl iodide penetration less than or equal to 2.5%' when tested in accordance with ASTM D3803-89 at a temperature of 30C (860F) and a relative humidity of 70%:

d. At least once per 24 months by:

1) Verifying that the pressure drop across the combined HEPA filters and charcoal adsorber banks is lecs than 6.25 inches Water Gauge while operating the system at a flow rate of 7600 cfm to 9800 cfm,

2) Verifying that the system starts on a Safety Injection test signal, and

3) Verifying that the heaters dissipate 50 +5 kW when tested in accordance with ANSI N510-1980.

• ANSI N510-1980 shall be used in place of ANSI NS10-1975 referenced in Regulatory Guide 1.52, Revision 2, March 1978.

MILLSTONE - UNIT 3 3/4 6-20 Amendment No. Z, as, i7, 0855 J9p, f7l, ;7f, J99, 206

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

e. After each complete or partial replacement of a HEPA filter bank, by verifying that the cleanup system satisfies the in-place penetration and bypass leakage testing acceptance criteria of less than 0.05% in accordance with ANSI N510-1980 for a DOP test aerosol while operating the system at a flow rate of 7600 cfm to 9800 cfm; and

f. After each complete or partial replacement of a charcoal adsorber bank, by verifying that the cleanup system satisfies the in-place penetration and bypass leakage testing acceptance criteria of less than 0.05% in accordance with ANSI NS10-1980 for a halogenated hydrocarbon refrigerant test gas while operating the system at a flow rate of 7600 cfm to 9800 cfm.

MILLSTONE - UNIT 3 3/4 6-21 Amendment No. Z. Ile $7 1 0257 100

-JAN 23 1995

CONTAINMENT SYSTEMS SECONDARY CONTAINMENT LIMITING CONDITION FOR OPERATION 3.6.6.2 on tda ry u-e r, ar.p h FE .

APPLICABILiTY: ODES 1. . 3. -nI '

ACTION:

With Secondary Containment inoperable, restore Secondarv hontainment to OPERABLE status within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

SURVEILLANCE REQUIREMENT 4 6.6.2.1. OPERABTLITY of Secondary Containment shall be demonstrated at least once per 31 days by verifying that each door in each access opening is closed except when the access opening is being used for normal transit entry and exit.

4.6.6.2.2 At least once per 24 months. verify each Supplementary Leak Collection and Release System produces a negative pressure of greater than or equal to 0.4 inch water gauge in the Auxiliary Building at 24'-6` elevation wjithin 120 seconds after a start signal.

MILLSTONE - UNIT 3 0856 3/4 6-22 Amendment No. 97, J0 , X #. 206

CONTAINMENT SYSTEMS SECONDARY CONTAINMENT STRUCTURAL INTEGRITY LIMITING CONDITION FOR OPERATION 3.6.6.3 The structural integrity of the Secondary Containment shall be maintained at a level consistent with the acceptance criteria in Specification 4.6.6.3.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTION:

With the structural integrity of the Secondary Containment not conforming to the above requirements, restore the structural integrity to within the limits within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

SURVEILLANCE REQUIREMENT 4.6.6.3 The structural integrity of the Secondary Containment shall be determined at the frequency specified in the Containment Leakage Rate Testing Program, by a visual inspection of the exposed accessible interior and exterior surfaces of the Secondary Containment and verifying no apparent changes in appearance of the concrete surfaces or other abnormal degradation. Any abnormal degradation of the Secondary Containment detected during the above required inspections shall be reported to the Commission in a Special Report pursuant to Specification 6.9.2 within 15 days.

MILLS07NE - UNIT 3 3/4 6-23 Amendment No. f7, WAS IIf, 18E 0711

3/4.7 PLANT SYSTEMS 3/4.7.1 TURBINE CYCLE SAFETY VALVES I TM1TTNn CflNflITTAn FnR nPFRATTnN 3.7.1.1 All main steam line Code safety valves shall be OPERABLE with lift settings as specified in Table 3.7-3.

APPLICABILITY: MODES 1, 2, and 3.

ACTION:

a. With one or more main steam line Code safety valves inoperable, operation in MODES 1, 2, and 3 may proceed provided, that within 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />, either the inoperable valve is restored to OPERABLE status or the Power Range Neutron Flux High Trip Setpoint is reduced per Table 3.7-1; otherwise, be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in HOT SHUTDOWN within the following 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />.

CIIRVF1I I ANrF RFQIITAFMFNTC 4.7.1.1 No additional Surveillance Requirements other than those required by Specification 4.0.5.

MILLSTONE - UNIT 3 3/4 7-1 Amendment No. 97, 217 0983

TABLE 3.7-1 MAXIMUM ALLOWABLE POWER RANGE NEUTRON FLUX HIGH SETPOINT WITH INOPERABLE STEAM LINE SAFETY VALVES I MAXIMUM NUMBER OF INOPERABLE MAXIMUM ALLOWABLE POWER RANGE SAFETY VALVES ON ANY NEUTRON FLUX HIGH SETPOINT OPERATING STEAM GENERATOR (PERCENT OF RATED THERMAL POWER) 65 2 46 3 28 TABLE 3.7-2 DELETED MILLSTONE - UNIT 3 3/4 7-2 Amendment No. ZT7,217 0983

TABLE 3.7-3 STEAM LINE SAFETY VALVES PER LOOP VALVE NUMBR LIFT SETTING* (+/-3%)** ORIFICE SIZE I

LOOP I RV22A 1185 psIg 16.0 square inches RV23A 1195 ps g 16.0 square inches RV24A 1205 psig 16.0 square inches RV25A 1215 psig 16.0 square inches RV26A 1225 ps g 16.0 square inches RV22B 1185 psig 16.0 square inches RV23B 1195 psig 16.0 square Inches RV24B 1205 ps1g 16.0 square inches RV25B 1215 ps1g 16.0 square Inches RV26B 1225 ps1g 16.0 square inches RV22C 1185 psig 16.0 square inches RV23C 1195 psig 16.0 square inches RV24C 1205 psig 16.0 square inches RV25C 1215 ps g 16.0 square inches RV26C 1225 psig 16.0 square inches LOOP 4 RV22D 1185 psig 16.0 square inches RV23D 1195 psig 16.0 square Inches RV24D 1205 psig 16.0 square inches RV25D 1215 psig 16.0 square inches RV26D 1225 psig 16.0 square inches

• The lift setting pressure shall correspond to ambient conditions of the valve at nominal operating temperature and pressure.

• • The lift setting shall be within +/- 1% following main steam line Code safety valve testing. I MILLSTONE - UNIT 3 3/4 7-3 Amendment No. 106 0278 MAR 1 71995

PLANT SYSTEMS AUXILIARY FEEDWATER SYSTEM LIMITING CONDITION FOR OPERATION 3.7.1.2 At least three independent steam generator auxiliary feedwater pumps and associated flow paths shall be OPERABLE with:

a. Two motor-driven auxiliary feedwater pumps, each capable of being powered from separate emergency busses, and

b. One steam turbine-driven auxiliary feedwater pump capable of being powered from an OPERABLE steam supply system.

APPLICABILMT: MODES I, 2, and 3.

ACTION:

a. With one auxiliary feedwater pump inoperable, restore the required auxiliary feedwater pumps to OPERABLE status within 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in HOT SHUTDOWN within the following 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />.

b. With two auxiliary feedwater pumps inoperable, be in at least HOT STANDBY within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in HOT SHUTDOWN within the following 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />.

c. With three auxiliary feedwater pumps inoperable, iumediately initiate corrective action to restore at least one auxiliary feedwater pump to OPERABLE status as soon as possible. Entry into an OPERATIONAL MODE pursuant to Specification 3.0.4 is not permitted with three auxiliary feedwater pumps inoperable.

SURVEILLANCE REQUIREMENTS 4.7.1.2.1 Each auxiliary feedwater pump shall be demonstrated OPERABLE:

a. At least once per 31 days by:

I

1) Verifying that each non-automatic valve in the flow path that is not locked, sealed, or otherwise secured in position is in its correct position; and

2) Verifying that each auxiliary feedwater control and isolation I valve in the flow path is in the fully open position when above 10% RATED THERMAL POWER.

MILLSTONE - UNIT 3 3/4 7-4 AMENDMENT NO. P7,iow 025n JAN 3 1995

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

<^. S- E -= E - -- nt

b. At least once per 92 'ags 22 - 1I Tr to Specif ication, .7>. -. :

f r- - -. r

• i-elfoos ; ..a.;-d e -- ! s-l .38 ua:

er,i/jriq ttfla~ .227 r 7eubneoie pump develops a e- Khan e 'Ir :0 7ual 3780 feet 14hen the -1conda -S ea L Slupp ressur5 Ok gra 9 e than 800 psig. The provisionS of Specification 4.0.4 are no:

applicable for entry into ilODE 3.

c. At least once per 24 months by verifying that each auxiliary feedwater pump starts as designed automatically upon receipt of an Auxiliary Feedwater Actuation test signal. For the steam turbine-driven auxiliary feedwater pump. the provisions of Specification 4.0.4 are not applicable for entry into MODE 3.

4.7.1.2.2 An auxiliary feedwater flow path to each steam generator shall be demonstrated OPERABLE following each COLD SHUTDOWN of greater than 30 days prior to entering MODE 2 by verifying flow to each steam generator.

MILLSTONE - UNIT 3 3/4 7-5 Amendment No. if, 100, 7, 206 0857

PLAMNT SYSTEMS DEMINERALIZED WATER STORAGE TANK LIMITING CONDITION FOR OPERATION 3.7.1.3 The demineralized water storage tank (DWST) shall be OPERABLE with a water volume of at least 334,000 gallons. I APPLICABILITY: MODES 1, 2, and 3. ACTION: With the DWST inoperable, within 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> either:

a. Restore the DWST to OPERABLE status or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in HOT SHUTDOWN within the following 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />, or

b. Demonstrate the OPERABILITY of the condensate storage tank (CST) as a backup supply to the auxiliary feedwater pumps and restore the DWST to OPERABLE status within 7 days or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in HOT SHUTDOWN within the following 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />.

SURVEILLANCE REQUIREMENTS 4.7.1.3.1 The DWST shall be demonstrated OPERABLE at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> by verifying the water volume is within its limits when the tank is the supply I source for the auxiliary feedwater pumps. 4.7.1.3.2 The CST shall be demonstrated OPERABLE at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> by verifying that the combined volume of both the DWST and CST is at least 384,000 gallons of water whenever the CST and DWST are the supply source for the auxiliary feedwater pumps. MILLSTONE - UNIT 3 3/4 7-6 Amendment No. 150 0534 Crn . i

PLANT SYSTEMS SPECIFIC ACTIVITY LIMITING CONDITION FOR OPERATION 3.7.1.4 The specific activity of the Secondary Coolant System shall be less than or equal to 0.1 microCurie/gram DOSE EQUIVALENT I-131. APPLICABILITY: MODES 1, 2, 3, and 4. ACTION: With the specific activity of the Secondary Coolant System greater than 0.1 microCurie/gram DOSE EQUIVALENT I-131, be in at least HOT STANDBY within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />. SURVEILLANCE REQUIREMENTS 4.7.1.4 The specific activity of the Secondary Coolant System shall be determined to be within the limit by performance of the sampling and analysis program of Table 4.7-1. MILLSTONE - UNIT 3 3/4 7-7

TABLE 4.7-1 SECONDARY COOLANT SYSTEM SPECIFIC ACTIVITY SAMPLE AND ANALYSIS PROGRAM TYPE OF MEASUREMENT SAMPLE AND ANALYSIS AND ANALYSIS FREQUENCY

1. Gross Radioactivity At least once per 72 hours3 days <br />0.429 weeks <br />0.0986 months <br />.

Determination

2. Isotopic Analysis for DOSE a) Once per 31 days, when-EQUIVALENT I-131 Concentration ever the gross radio-activity determination indicates concentrations greater than 10% of the allowable limit for radioiodines.

b) Once per 6 months, when-ever the gross radio-activity determination indicates concentrations less than or equal to 10% of the allowable limit for radioiodines. MILLSTONE - UNIT 3 3/4 7-8

PLANT SYSTEMS MAIN STEAM LINE ISOLATION VALVES LIMITING CONDITION FOR OPERATION 3.7.1.5 Four main steam line isolation valves (MSIVs) shall be OPERABLE. I APPLICABILITY: MODE 1 MODES 2, 3, and 4, except when all MSIVs are closed and deactivated. ACTION: MODE 1: With one NSIV inoperable, POWER OPERATION may continue provided the Inoperable valve is restored to OPERABLE status within 8 hours0.333 days <br />0.0476 weeks <br />0.011 months <br />; otherwise be in MODE 2 within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />. MODES 2, 3, and 4: With one or more MSIVs inoperable, subsequent operation in MODE 2, or 3, or 4 may proceed provided the inoperable isolation valve(s) is (are) closed* within 8 hours0.333 days <br />0.0476 weeks <br />0.011 months <br /> and verified closed once per 7 days. Otherwise, be in HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the I following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />. Separate condition entry is allowed for each MSIV. SURVEILLANCE REQUIREMENTS 4.7.1.5.1 DELETED 4.7.1.5.2 Each MSIV shall be demonstrated OPERABLE, pursuant to Specification 4.0.5, by verifying full closure within 10 seconds (120 seconds for MODE 4 only) on an actual or simulated actuation signal. The provisions of Specification 4.0.4 are not applicable for entry into MODE 4 or MODE 3.

*The NSIVs may be opened to perform Surveillance Requirement 4.7.1.5.2 when Reactor Coolant System temperature is greater than or equal to 320'F.

MILLSTONE - UNIT 3 3/4 7-9 Amendment No. *f, go, WIP. W. 0702 Joys 185

PLANT SYSTEMS STEAM GENERATOR ATMOSPHERIC RELIEF BYPASS LINES LIMITING CONDITION FOR OPERATION 3.7.1.6 Each steam generator atmospheric relief bypass valve (SGARBV) line shall be OPERABLE, with the associated main steam atmospheric relief isolation (block) valve in the open position. APPLICABILITY: MODES 1, 2, and 3, MODE 4 when steam generator is relied upon for heat removal. ACTIONS

a. With one required SGARBV line inoperable, restore required SGARBV line to OPERABLE status within 7 days or be in at least MODE 3 within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and be in MODE 4 without reliance upon steam generator for heat removal within the next 18 hours0.75 days <br />0.107 weeks <br />0.0247 months <br />. LCO 3.0.4 is not applicable.

b. With two or more required SGARBV lines inoperable, restore all but one required SGARBV line to OPERABLE status within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> or be in at least MODE 3 within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and be in MODE 4 without reliance upon steam generator for heat removal within the next 18 hours0.75 days <br />0.107 weeks <br />0.0247 months <br />.

SURVEILLANCE REQUIREMENTS 4.7.1.6.1 Verify one complete cycle of each SGARBV every 18 months. 4.7.1.6.2 Verify one complete cycle of each main steam atmospheric relief isolation (block) valve every 18 months. MILLSTONE - UNIT 3 3/4 7-9a Amendment No.151 1

THIS PAGE INTENTIONALLY LEFT BLANK MILLSTONE - UNIT 3 3/4 7-10 Amendment No. 214 0875

PLANT SYSTEMS 3/4.7.3 REACTOR PLANT COMPONENT COOLING WATER SYSTEM LIMITING CONDITION FOR OPERATION 3.7.3 At least two indeperden_ e:-.-r i , ,- - 0 loops shall be OPERABLE. APPLICABILITY: . MODES 1. 2. 31: . ACTION: With only one reactor plant component cooling wa-ter arety loop OPERABLE. re-store at least two loops to OPERABLE status within 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the followina 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />. SURVEILLANCE REQUIREMENTS 4.7.3 At least two reactor plant component cooling water safety loops shall be demonstrated OPERABLE:

a. At least once per 31 days by verifying that each valve (manual power-operated, or automatic) servicing safety-related equipment that is not locked, sealed, or otherwise secured in position is in its correct position; and

b. At least once per 24 months by verifying that:

1) Each automatic valve actuates to its correct position on its associated Engineered Safety Feature actuation signal, and

2) Each Component Cooling Water System pump starts automatically on an SIS test signal.

MILLSTONE - UNIT 3 3/4 7-11 Amendment No.*Z7, 206 0858

PLANT SYSTEMS 3/4.7.4 SERVICE WATER SYSTEM LIMITING CONDITION FOR OPERATION 3.7.4 At least two independ=- :L .Aar APPLICABILITT: MODES I. 2. 3' ACTION: With only one service water loop OPERABLE. ,-store at least lOops

                                                                  !;. to OPERABLE status within 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> or be in at least HOT STANDBY Within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

SURVEILLANCE REQUIREMENTS 4.7.4 At least two service water loops shall be demonstrated OPERABLE:

a. At least once per 31 days by verifying that each valve (manual.

power-operated. or automatic; servicing safety-related equipment that is not locked. sealed. or otherwise secured in position is in its correct position; and

b. At least once per 24 months by verifying that:

1) Each automatic valve servicing safety-related equipment actuates to its correct position on its associated Engineered Safety Feature actuation signal, and

2) Each Service 'Wlater System pump starts automatically on an SIS test signal.

MILLSTONE - UNIT 3 3/4 7-12 Amendment No. fl77 206 0858

PLANT SYSTEMS 3/4.7.5 ULTIMATE HEAT SINK LIMITING CONDITION FOR OPERATION 3.7.5 The ultimate heat sink (UHS) shall be OPERABLE with an average water temperature of less than or equal to 75F. I APPLICABILITY: MODES 1, 2, 3, and 4. ACTION: If the UHS temperature is above 75F, monitor the UHS temperature once per hour for 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />. If the UHS temperature does not drop below 75F during this period, place the plant in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />. During this period, if the UHS temperature increases above 77F, place the plant in HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />. SURVEILLANCE REQUIREMENTS 4.7.5 The UHS shall be determined OPERABLE:

a. At least once per 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> by verifying the average water temperature to be within limits.

b. At least once per 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> by verifying the average water temperature to be within limits when the average water temperature exceeds 70F.

MILLSTONE - UNIT 3 3/4 7-13 Amendment No. 119 0356

                                                                      ;'~- ^ a 1995

THIS PAGE INTENTIONALLY LEFT BLANK MILLSTONE - UNIT 3 3/4 7-14 Amendment No. All, 214 0876

PLANT SYSTEMS 3/4.7.7 CONTROL ROOM EMERGENCY VENTILATION SYSTEM LIMITING CONDITION FOR OPERATION 3.7.7 Two independent Control Room Emergency Air Filtration Systems shall be OPERABLE.# APPLICABILITY: MODES 1, 2,3,4,5 and 6. During fuel movement within containment or the spent fuel pool. ACTION: MODES 1, 2, 3 and 4:

a. With one Control Room Emergency Air Filtration System inoperable, restore the inoperable system to OPERABLE status within 7 days or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

b. With both Control Room Emergency Air Filtration Systems inoperable, except as specified in ACTION c., immediately suspend the movement of fuel within the spent fuel pool. Restore at least one inoperable system to OPERABLE status within 1 hour or be in HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

c. With both Control Room Emergency Air Filtration Systems inoperable due to an inoperable Control Room boundary, immediately suspend the movement of fuel within the spent fuel pool and restore the Control Room boundary to OPERABLE status within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> or be in HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

MODES 5 and 6, and durimg fuel movement within containment or the spent fuel pool:

d. With one Control Room Emergency Air Filtration System inoperable, restore the inoperable system to OPERABLE status within 7 days. After 7 days, either initiate and maintain operation of the remaining OPERABLE Control Room Emergency Air Filtration System in the recirculation mode of operation, or immediately suspend the movement of fuel.

e. With both Control Room Emergency Air Filtration Systems inoperable, or with the OPERABLE Control Room Emergency Air Filtration System required to be in the recirculation mode by ACTION d. not capable of being powered by an OPERABLE emergency power source, immediately suspend the movement of fuel.

1. The Control Room boundary may be opened intermittently under administrative control.

MILLSTONE - UNIT 3 3/4 7-15 Amendment No. 2, 484, I0, 219

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS 4.7.7 Each Control Room Emergency Air Filtration System shall be demonstrated OPERABLE:

a. At least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> by verifying that the control room air temperature is less than or equal to 950 F;

b. At least once per 31 days on a STAGGERED TEST BASIS by initiating, from the control room, flow through the HEPA filters and charcoal adsorbers and verifying a system flow rate of 1,120 cfm +20% and that the system operates for at least 10 continuous hours with the heaters operating;

c. At least once per 24 months or (1) after any structural maintenance on the HEPA filter or charcoal adsorber housings, or (2) following painting, fire, or chemical release in any ventilation zone communicating with the system by:

1) Verifying that the system satisfies the in-place penetration and bypass leakage testing acceptance criteria of less than 0.05% and uses the test procedure guidance in Regulatory Position C.5.a, C.5.c, and C.5.d of Regulatory Guide 1.52, Revisions 2, March 1978,* and the system flow rate is 1,120 cfm +20%;

2) Verifying, within 31 days after removal, that a laboratory analysis of a representative carbon sample obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978,* shows the methyl iodide penetration less than or equal to 2.5% when tested in accordance with ASTM D3803-89 at a temperature of 300C (860 F), a relative humidity of 70%, and a face velocity of 54 ft/min; and

3) Verifying a system flow rate of 1,120 cfm +20% during system operation when tested in accordance with ANSI N510-1980.

d. After every 720 hours30 days <br />4.286 weeks <br />0.986 months <br /> of charcoal adsorber operation, by verifying, within 31 days after removal, that a laboratory analysis of a representative carbon sample obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978,* shows the methyl iodide penetration less than or equal to 2.5% when tested in accordance with ASTM D3803-89 at a temperature of 30'C (860 F), and a relative humidity of 70%, and a face velocity of 54 ft/min.

e. At least once per 24 months by:

1) Verifying that the pressure drop across the combined HEPA filters and charcoal adsorber banks is less than 6.75 inches Water Gauge while operating the system at a flow rate of 1,120 cfm +20%;

MILLSTONE - UNIT 3 3/4 7-16 Amendment No. Z , } }, A*, 0930 7o 206

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) (2) Verifying that the system maintains the control room at a positive pressure of greater than or equal to 1/8 inch Water Gauge at less than or equal to a pressurization flow of 230 cfin relative to adjacent areas and outside atmosphere during the filtered pressurization mode of operation; and I (3) Verifying that the heaters dissipate 9.4 +1 kW when tested in accordance with ANSI N510-1980.

f. After each complete or partial replacement of a HEPA filter bank, by verifying that the cleanup system satisfies the in-place penetration and bypass leakage testing acceptance criteria of less than 0.05% in accordance with ANSI N510-1980 for a DOP test aerosol while operating the system at a flow rate of 1120 cfm +20%; and

g. After each complete or partial replacement of a charcoal adsorber bank, by verifying that the cleanup system satisfies the in-place penetration and bypass leakage testing acceptance criteria of less than 0.05% in accordance with ANSI N510-1980 for a halogenated hydrocarbon refrigerant test gas while operating the system at a flow rate of 1120 cfm +20%.

• ANSI N510-1980 shall be used in place of ANSI N510-1975 referenced in Regulatory Guide 1.52, Revision 2, March 1978.

MILLSTONE - UNIT 3 3/4 7-17 Amendment No. -, 423-,-G8,3, 220

PLANT SYSTEMS 3/4.7.8 CONTROL ROOM ENVELOPE PRESSURIZATION SYSTEM LIMITING CONDITION FOR OPERATION 3.7.8 Two independent Control Room Envelope Pressurization Systems shall be OPERABLE.# APPLICABILITY: MODES 1, 2,3,4,5 and 6. During fuel movement within containment or the spent fuel pool. ACTION: MODES 1,2,3, and 4:

a. With one Control Room Envelope Pressurization System inoperable, restore the system to OPERABLE status within 7 days, or be in HOT STANDBY within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

b. With both Control Room Envelope Pressurization Systems inoperable, except as specified in ACTION c. or ACTION d., immediately suspend the movement of fuel within the spent fuel pool. Restore at least one inoperable system to OPERABLE status within 1 hour or be in HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

c. With both Control Room Envelope Pressurization Systems inoperable due to an inoperable Control Room boundary, immediately suspend the movement of fuel within the spent fuel pool. Restore the Control Room boundary to OPERABLE status within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> or be in HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

d. With both Control Room Envelope Pressurization Systems inoperable during the performance of Surveillance Requirement 4.7.8.c and the system not being tested under administrative control, immediately suspend the movement of fuel within the spent fuel pool. Restore at least one inoperable system to OPERABLE status within 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> or be in HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

MODES 5 and 6, and fuel movement within containment or the spent fuel pool:

e. With one Control Room Envelope Pressurization System inoperable, restore the inoperable system to OPERABLE status within 7 days. After 7 days, immediately suspend the movement of fuel.

f. With both Control Room Envelope Pressurization Systems inoperable, immediately suspend the movement of fuel.

X The Control Room boundary may be opened intermittently under administrative control. MILLSTONE - UNIT 3 3/4 7-18 Amendment No. 48, 203,219

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS 4.7.8 Each Control Room Envelope Pressurization System shall be demonstrated OPERABLE:

a. At least once per 7 days by verifying that the storage air bottles are pressurized to greater than or equal to 2200 psig,

b. At least once per 31 days on a STAGGERED TEST BASIS by verifying that each valve (manual, power operated or automatic) in the flow path not locked, sealed or otherwise secured in position, is in its correct position, and

c. At least once per 24 months or following a major alteration of the control room envelope pressure boundary by:

1. Verifying that the control room envelope is isolated in response to a Control Building Isolation test signal,

2. Verifying that after a 60 second time delay following a Control Building Isolation test signal, the control room envelope pressurizes to greater than or equal to 1/8 inch W.G. relative to adjacent areas and outside atmosphere, and

3. Verifying that the positive pressure of Specification 4.7.8.c.2 is maintained for greater than or equal to 60 minutes.

MILLSTONE - UNIT 3 3/4 7-19 Amendment No. JZZ, ZIg, 206 0931

PLANT SYSTEMS 3/4.7.9 AUXILIARY BUILDING FILTER SYSTEM LIMITING CONDITION FOR OPERATION 3.7.9 Two independent Auxiliary Building Filter Systems shall be OPERABLE. APPLICABILITY: MODES 1, 2, 3, and 4. ACTION: With one Auxiliary Building Filter System inoperable, restore the inoperable system to OPERABLE status within 7 days or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />. In addition, comply with the ACTION requirements of Specification 3.6.6.1. SURVEILLANCE REQUIREMENTS 4.7.9 Each Auxiliar Building Filter System shall be demonstrated OPERABLE:

a. At least once per 31 days on a STAGGERED TEST BASIS by initiating, from the control room, flow through the HEPA filters and charcoal adsorbers and verifying a system flow rate of 30,000 cfm +10% and that the system operates for at least 10 continuous hours with the heaters operating;

b. At least once per 24 months or (1) after any structural maintenance on the HEPA filter or charcoal adsorber housings, or (2) following painting, fire, or chemical release in any ventilation zone communicating with the system by:

1) Verifying that the cleanup system satisfies the in-place penetration and bypass leakage testing acceptance criteria of less than 0.05% and uses the test procedure guidance in Regulatory Positions C.5.a, C.5.c, and C.5.d of Regulatory Guide 1.52, Revision 2, March 1978,* and the system flow rate is 30,000 cfm +10%;

2) Verifying, within 31 days after removal, that a laboratory analysis of a representative carbon sample obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978,* shows the methyl MILLSTONE - UNIT 3 3/4 7-20 Amendment No. Z, i7, fly, Of, 0931 tFI, 206

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS iodide penetr1r r ran -ttiGam ro _ ,hen ts-tei n acc"d anrce:r

                   -.                     S     5ll-.

_ . n-3 1 i- J G~~~ ~ ~ S T;ei!;j1-11510-1980.

c. After every 720 hours30 days <br />4.286 weeks <br />0.986 months <br /> L f Tharcoal adsorber operation. b verifying, within 31 days aftr removal, that a laboratory analysis of a representative carbon sample obtained in accordance with Regulatory PoSition C.6.b of Regulatory Guide 1.52. Revision 2, March 1978.* shows the methyl iodide penetration lVss than or equal lo 2.5 when tested in accordance with ASTM D38u3-89 at a temperature of 30 C (865F). a relative humidity of 70%. and a face "elocity of 52 ft min:

d. At least once per 24 months by:

1) Verifying that the pressure drop across the combined HEP.-.

filters and charcoal adsorber banks is less than o.3 inches Water Gauge while operating the system at a flow rate of 30,000 cfm +/-10.%.

2) Verifying that the system starts on a Safety Injection test signal. and

3) Verifying that the heaters dissipate 180 +18 kW '.qhen tested in accordance with ANSI 11510-1980.

e. After each complete or partial replacement of a HEPA filter bank, by verifying that the cleanup system satisfies the in-place penetration and bypass leakage testing acceptance criteria of less than 0.05% in accordance with ANSI N510-1980 for a DOP test aerosol while operating the system at a flow rate of 30,000 cfm +10%'; and

f. After each complete or partial replacement of a charcoal adsorber bank, by verifying that the cleanup system satisfies the in-place penetration and bypass leakage testing acceptance criteria of less than 0.05% in accordance with ANSI N510-1980 for a halogenated hydrocarbon refrigerant test gas while operating the system at a flow rate of 30,000 cfm +10%.

• ANSI N510-1980 shall be used in place of ANSI N510-1975 referenced in Regulatory Guide 1.52, Revision 2, March 1978.

MILLSTONE - UNIT 3 3/4 7-21 Amendment No. Z, 97, 1/Z, J9' 206 0860

PLANT SYSTEMS 3/4.7.10 SNUBBERS LIMITING CONDITION FOR OPERATION 3.7.10 All snubbers shall be OPERABLE. The only snubbers excluded from the requirements are those installed on nonsafety-related systems and then only if their failure or failure of the system on which they are installed would have no adverse effect on any safety-related system. APPLICABILITY: MODES 1, 2, 3, and 4. MODES 5 and 6 for snubbers located on systems required OPERABLE in those MODES. ACTION: With one or more snubbers inoperable on any system, within 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> replace or restore the inoperable snubber(s) to OPERABLE status and perform an engineering evaluation per Specification 4.7.10g. on the attached component or declare the attached system inoperable and follow the appropriate ACTION statement for that system. SURVEILLANCE REOUIREMENTS 4.7.10 Each snubber shall be demonstrated OPERABLE by performance of the following augmented inservice inspection program and the requirements of Specification 4.0.5.

a. Insoection TvDes As used in this specification, "type of snubber' shall mean snubbers of the same design and manufacturer, irrespective of capacity.

b. Visual Inspections Snubbers are categorized as inaccessible or accessible during reactor operation. Each of these categories (inaccessible and accessible) may be inspected independently according to the schedule determined by Table 4.7-2. The visual inspection interval for each type of snubber shall be determined based upon the criteria provided in Table 4.7-2.

c. Visual InsDection AcceDtance Criteria Visual inspections shall verify that (1)the snubber has no visible indications of damage or impaired OPERABILITY, (2) attachments to the foundation or supporting structure are functional, and (3) fasteners for the attachment of the snubber to the component and to the snubber anchorage are functional. Snubbers which appear inoperable as a result of visual inspections shall be classified as unacceptable and may be reclassified acceptable for the purpose of establishing the next visual inspection interval, provided that (1)the cause of the rejection is clearly established and remedied for that particular snubber and for other snubbers irrespective of MILLSTONE - UNIT 3 3/4 7-22 Amendment No. At, fl,71 0033 nr*. qr t

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) type that may be generically >..ptivle: and 12) thE affected snubber is functionally is ed :j t te - ian-unzcridi tMio and determined OPERABLE Der Specificsatior I. l1f. f i. snubbers found connected to an inoperable on - c ,ir hal b zhaM counted as unacceptablea r t rnin -I a -dx inrspection interval. A revie. and eva I at',c r:ha I e r-rf cn-' d3cumented to justify continued eperat or . 'n ina aIn ,. ubs if continued operation cannot be ]u ti in. the Snubber shlI be declared inoperable and the ACTIO. r-equLIrere nr chal be -et.

d. Transient Event Inspection An inspection shall be performed of all snubbers attached to sections of systems that have experienced unexpected. potentially damaging transients as determined from a review of operational data and a visual inspection of the systems within 6 months following such an event. In addition to satisfying the visual inspection acceptance criteria, freedom-of-motion of mechanical snubbers shall be verified using at least one of the following: (1) manually induced snubber movement; or (2) evaluation of in-place snubber piston setting: or (3) stroking the mechanical snubber through its full range of travel.

e. Functional Tests During the first refueling shutdown and at least once per 24 months thereafter,* a representative sample of snubbers of each type shall be tested using one of the following sample plans. The sample plan for each type shall be selected prior to the test period and cannot be changed during the test period. The NRC Regional Administrator shall be notified in writing of the sample plan selected for each snubber type prior to the test period or the sample plan used in the prior test period shall be implemented:

1) At least 10% of the total of each type of snubber shall be functionally tested either in-place or in a bench test. For each snubber of a type that does not meet the functional test acceptance criteria of Specification 4.7.10f., an additional 5%

of that type of snubber shall be functionally tested until no more failures are found or until all snubbers of that type have been functionally tested; or

• Except the surveillance related to snubber functional testing due no later than March 10, 1999 may be deferred until the end of the next refueling outage or no later than September 10, 1999, whichever is earlier.

MILLSTONE - UNIT 3 3/4 7-23 Amendment 7, 70, 700 X7, 47, 206 0861

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

e. Functional Tests (Continued)

2) A representative sample or each type of snubber shall be func-tionally tested in accordance with Figure 4.7-1. "C" is the total number of snubbers of a type found not meeting the accept-ance requirements of Specification 4.7.10f. The cumulative number of snubbers of a type tested is denoted by "N". Test results shall be plotted sequentially in the order of sample assignment (i.e. each snubber shall be plotted by its assigned order in the random sample, not by the order of testing). If at any time the point plotted falls in the "Acceptw region, testing of snubbers of that type may be terminated. When the point plotted lies in the "Continue Testing" region, additional snubbers of that type shall be tested until the point falls in the "Accept" region or the "Reject" region, or all the snubbers of that type have been tested; or

3) An initial representative sample of 55 snubbers shall be func-tionally tested. For each snubber type which does not meet the functional test acceptance criteria, another sample of at least one-half the size of the initial sample shall be tested until the total number tested is equal to the initial sample size multiplied by the factor, 1 + C/2, where 'C" is the number of snubbers found which do not meet the functional test acceptance criteria. The results from this sample plan shall be plotted using an "Accept' line which follows the equation N = 55(1

• C/2). Each snubber point should be plotted as soon as the snubber is tested. If the point plotted falls on or below the "Accept" line, testing of that type of snubber may be terminated. If the point plotted falls above the "Accept" line, testing must continue until the point falls in the "Accept"

               *region or all the snubbers of that type have been tested.

Testing equipment failure during functional testing may invalidate that day's testing and allow that day's testing to resume anew at a later time provided all snubbers tested with the failed equipment during the day of equipment failure are retested. The representative sample selected for the functional test sample plans shall be randomly selected from the snubbers of each type and reviewed before beginning the testing. The review shall ensure, as far as practicable, that they are representative of the various configurations, operating environments, range of size, and capacity of snubbers of each type. Snubbers placed in the same location as snubbers which failed the previous functional test shall be retested at the time of the next functional test but shall not be included in the sample plan. If during the functional testing, additional sampling is required due to failure of only one type of snubber, the functional test results shall be reviewed at that time to determine if additional samples should be limited to the type of snubber which has failed the functional testing. MILLSTONE - UNIT 3 3/4 7-24 Amendment No. T6 APR 7 1S88

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

f. Functional Test Acceptance Criteria The snubber functional test shall verify that:

1) Activation (restraining action) is achieved within the specified range in both tension and compression;

2) Snubber bleed, or release rate where required, is present in both tension and compression, within the specified range;

3) For mechanical snubbers, the force required to initiate or maintain motion of the snubber is within the specified range in both directions of travel; and

4) For snubbers specifically required not to displace under continuous load, the ability of the snubber to withstand load without displacement.

Testing methods may be used to measure parameters indirectly or parameters other than those specified if those results can be correlated to the specified parameters through established methods.

g. Functional Test Failure Analysis An engineering evaluation shall be made of each failure to meet the functional test acceptance criteria to determine the cause of the failure. The results of this evaluation shall be used, if applicable, in selecting snubbers to be tested in an effort to determine the OPERABILITY of other snubbers irrespective of type which may be subject to the same failure mode.

For the snubbers found inoperable, an engineering evaluation shall be performed on the components to which the inoperable snubbers are attached. The purpose of this engineering evaluation shall be to determine if the components to which the inoperable snubbers are attached were adversely affected by the inoperability of the snubbers in order to ensure that the component remains capable of meeting the designed service. If any snubber selected for functional testing either fails to lock up or fails to move, i.e., frozen-in-place, the cause will be evaluated and, if caused by manufacturer or design deficiency, all snubbers of the same type subject to the same defect shall be func-tionally tested. This testing requirement shall be independent of the requirements stated in Specification 4.7.10e. for snubbers not meeting the functional test acceptance criteria. MILLSTONE - UNIT 3 3/4 7-25

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

h. Functional Testing of Repaired and Replaced Snubbers Snubbers which fail the visual inspection or the functional test

            -acceptance criteria shall be repaired or replaced. Replacement snubbers and snubbers which have repairs which might affect the functional test results shall be tested to meet the functional test criteria before installation in the unit. Mechanical snubbers shall have met the acceptance criteria subsequent to their most recent service, and the freedom-of-motion test must have been performed within 12 months before being installed in the unit.

i. Snubber Service Life Procram The service life of hydraulic and mechanical snubbers shall be monitored to ensure that the service life is not exceeded between surveillance inspections. The maximum expected service life for various seals, springs, and other critical parts shall be deter-mined and established based on engineering information and shall be extended or shortened based on monitored test results and failure history. Critical parts shall be replaced so that the maximum service life will not be exceeded during a period when the snubber is required to be OPERABLE. The parts replacements shall be docu-mented and the documentation shall be retained in accordance with Quality Assurance Program Topical Report.

MILLSTONE - UNIT 3 3/4 7-26 Amendment No. 173 0832

TABLE 4.7-2 SNUBBER VISUAL INSPECTION INTERVAL NUMBER OF UNACCEPTABLE SNUBBERS Population Column A Column B Column C or Category Extend Interval Repeat Interval Reduce Interval

  -(Notes I and 2)        (Notes 3 and 6)      (Notes 4 and 6)    (Notes 5 and 6) 1                      0                    0                  1 80                      0                    0                  2 100                      0                    1                  4 150                      0                    3                  8 200                      2                    5                 13 300                      5                   12                 25 400                      8                   18                 36 500                     12                   24                 48 750                     20                   40                 78 1000 or greater              29                   56                109 Note 1:        The next visual inspection interval for a snubber population or category size shall be determined based upon the previous inspection interval and the number of unacceptable snubbers found during that interval. Snubbers may be categorized, based upon their accessibility during power operation, as accessible or inaccessible.

These categories may be examined separately or Jointly. However, the licensee must make and document that decision before any inspection and shall use that decision as the basis upon which to determine the next inspection interval for that category. Note 2: Interpolation between population or category sizes and the number of unacceptable snubbers is permissible. Use next lower integer for the value of the limit for Columns A, B. or C if that integer included a fractional value of unacceptable snubbers as determined by interpolation. Note 3: If the number of unacceptable snubbers is equal to or less than the number in Column A, the next inspection interval may be twice the previous interval but no greater than 48 months. Note 4: If the number of unacceptable snubbers is equal to or less than the number in Column B but greater than the number in Column A, the next inspection interval shall be the same as the previous interval. Note 5: If the number of unacceptable snubbers Is equal to or greater than the number in Column C, the next inspection interval shall be two-thirds of the previous interval. However, if the number of unacceptable snubbers is less than the number in Column C but greater than the number in Column B. the next interval shall be reduced proportionally by interpolation, that is, the previous interval shall be reduced by a factor that is one-third of the ratio of the difference between the number of unacceptable snubbers found during the previous interval and the number in Column B to the difference in the numbers in Columns B and C. MILLSTONE - UNIT 3 3/4 7-27 Amendment No. 7,10 0 0251 JAN 3 1995

                      -          TABLE 4.7-2 SNUBBER VISUAL INSPECTION INTERVAL Note 6:     The provisions of Specification 4.0.2 are applicable for all inspection intervals up to and including 48 months.

MILLSTONE - UNIT 3 0281 3/4 7-28 Amendment No. 1?.10o 1J1tlj3 1T-;: I

t0 9 S 7 6 C 6 4 3 2 1 U a 10 20 3D 40 60 60 70 80 90 100 N FIGURE 4.7-1 SAMPLE PLAN 2) FOR SNUBBER FUNCTIONAL TEST MILLSTONE - UNIT 3 0201 3/4 7-29 Amendment No. ifI 100 JAN 3 1995 I

THIS PAGE INTENTIONALLY LEFT BLANK MILLSTONE - UNIT 3 3/4 7-30 Amendment No. 77, J9P, 0877 214

THIS PAGE INTENTIONALLY LEFT BLANK MILLSTONE - UNIT 3 3/4 7-31 Amendment No. J00, 0877 214

3/4.7.14 AREA TEMPERATURE MONITORING LIMITING CONDITION FOR OPERATION 3.7.14 The temperature limit of each area shown in Table 3.7-6 shall not be exceeded. APPLICABILITY: Whenever the equipment in an affected area is required to be OPERABLE. With one or more areas exceeding the temperature limit(s) shown in Table 3.7-6:

a. By less than 20F and for less than 8 hours0.333 days <br />0.0476 weeks <br />0.011 months <br />, record the cumulative time and the amount by which the temperature in the affected area(s) exceeded the limit(s).

b. By less than 20'F and for greater than or equal to 8 hours0.333 days <br />0.0476 weeks <br />0.011 months <br />, prepare and submit to the Commission within 30 days, pursuant to Specification 6.9.2, a Special 'Report that provides a record of the cumulative time and the amount by which the temperature in the affected area(s) exceeded the limit(s) and an analysis to demonstrate the continued OPERABILITY of the affected equipment.

The provisions of Specification 3.0.3 are not applicable.

c. With one or more areas exceeding the temperature limit(s) shown in Table 3.7-6 by greater than or equal to 200F, prepare and submit a Special Report as required by ACTION b. above and within 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> either restore the area(s) to within the temperature limit(s) or declare the equipment in the affected area(s) inoperable.

SURVEILLANCE REQUIREMENTS 4.7.14 The temperature in each of the areas shown in Table 3.7-6 shall be determined to be within its limits:

a. At least once per seven days when the alarm is OPERABLE, and;

b. At least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> when the alarm is inoperable.

MILLSTONE - UNIT 3 3/4 7-32 Amendment Ho. R7. Fl, YPP 141 0611 Ji-; 2H 4 i907

TABLE 3.7-6 AREA TEMPERATURE MONITORING TEMPERATURE LIMIT (OF)

1. AUXILIARY BUILDING AB-02, VCT and Boric Acid Transfer Pump Area, El 43'6' < 120 AB-03, Charging Pump Area, El 24'6' < 110 AB-04, General Area, El 66'6' 1 120 AB-06, General Area, El 43'68 < 120 AB-07, General Area, El 4'6' < 120 AB-08, General Area (East), El 4'6' <S 120 AB-09, General Area (South), El 4'60 £ 120 AB-10, General Area, El 4'6 1 120 AB-li, General Area, El 4316' < 120 AB-13, General Area (North), El 4'6 < 120 AB-16, Supplemental Leak Collection Filter Area, El 66'6 < 120 AB-19, MCC/Rod Drive Area, El 24'60 < 120 AB-21, MCC Air Conditioning Room, El 66'60 c 120 AB-22, Rod Drive Area, El 43'6' < 120 AB-25, Charging Pump Area, El 24'6w < 110 AB-26, RPCCW Pump Area, El 24'66 < 110 AB-29, General Area (Southeast), El 24'60 < 120 AB-33, Boric Acid Tank Area, El 43'60 < 120 AB-35, Boric Acid Tank Area, El 43'60 < 120 AB-39, Fuel Building and Auxiliary Building Filter Area, El 66'6K 1 120 MILLSTONE - UNIT 3 3/4 7-33 Amendment No.10 0261 'JAR: 3 1995

TABLE 3.7-6 (Continued) AREA TEMPERATURE MONITORING AM IE 'RATURE L MIT ( F)

2. CONTROL BUILDING CB-01 Switchgear and Battery Rooms, El 4'6' 1 104 CB-02 , Cable Spreading Room, El 24'6 < 110 CB-03 9 Control and Computer Rooms, El 47'60 < 95 CB-04 9 Chiller Room, El 64'60 < 104 CB-05

• Mechanical Equipment Room, El 64-6' < 104

3. CONTAINMENT CS-O1

• Inside Crane Wall, El all except CS-03 and CS-04 1 120 CS-02 Outside Crane Wall, El all 1 120 CS-03. Pressurizer Cubicle, El all < 130 CS-04, Inside Crane wall, El 51'4 except CS-03 and steam 1 120 generator enclosures

4. INTAKE STRUCTURE CW-01, Entire Building '< 110

5. DIESEL

          .. GENERATOR..BUILDING DG-Ol,    Entire Building                                         < 120

6. ESF BUILDIN ES-O1, HVAC and MCC Area, El 36'6 < 110 ES-02, SIH Pump Area, El 21'68 < 110 ES-03, Pipe Tunnel Area, El 4'6' < 110 ES-04, RHS Cubicles, El all < 110 ES-05, RSS Cubicles, El all < 110 ES-06, Motor Driven Auxiliary Feedwater Pump Area, El 24'-6n < 110 ES-07, Turbine Driven Auxiliary Feedwater Pump C 110 Area, El 24'60 MILLSTONE - UNIT 3 3/4 7-34 Amendment No. ZF. 100 I 0261 JAN 3 199l

TABLE 3.7-6 (Continued) AREA TEMPERATURE MONITORING AREA TEMPERATURE LIMIT (OF)

7. FUEL BUILDING FB-02, Fuel Pool Pump Cubicles, El 24'6' FB-03, General Area, El 52'4"

8. FUEL OIL VAULT

                                                               < 119
                                                               < 108             I FV-01, Diesel Fuel Oil Vault                                    < 95

9. HYDROGEN RECOMBINER BUILDING HR-01, Recombiner Skid Area, El 24'6" < 125 HR-02, Controls Area, El 24'6" < 110 HR-03, Sampling Area, El 24'6" < 110 HR-04, HVAC Area, El 37'6" < 110

10. MAIN STEAM VALVE BUILDING MS-01, Areas above El. 58'0" < 140 MS-02, Areas below El. 58'0' < 140

11. TURBINE BUILDING TB-01, Entire Building < 115

12. TUNNEL TN-02, Pipe Tunnel-Auxiliary, Fuel and ESF Building < 112

13. YARD YD-01, Yard < 115 MILLSTONE - UNIT 3 . 3/4 7-35 Amendment No. Y7, lg, 182 0619 SEP I ? Pnrio

J/Q.6 tLCt6IlULKL runcLf J3Ii3CIIJ 3/4.8.1 A.C. SOURCES OPERATING LIMITING CONDITION FOR OPERATION 3.8.1.1 As a minimum, the following A.C. electrical power sources shall be OPERABLE:

a. Two physically independent circuits between the offsite transmission network and the onsite Class 1E Distribution System, and

b. Two separate and independent diesel generators, each with:

1) A separate day tank containing a minimum volume of 278 gallons of fuel,

2) A separate Fuel Storage System containing a minimum volume of 32,760 gallons of fuel,

3) A separate fuel transfer pump,

4) Lubricating oil storage containing a minimum total volume of 280 gallons of lubricating oil, and

5) Capability to transfer lubricating oil from storage to the diesel generator unit.

APPLICABILITY: MODES 1, 2, 3, and 4. ACTION: Inoperable Equipment Required Action

a. One offsite a.1 Perform Surveillance Requirement circuit 4.8.1.1.1.a for remaining offsite circuit within 1 hour prior to or after entering this condition, and at least once per 8 ihours thereafter.

AND a.2 Restore the inoperable offsite circuit to OPERABLE status within 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

b. One diesel b.1 Perform Surveillance Requirement generator 4.8.1.1.1.a for the offsite circuits within 1 hour prior to or after entering this condition, and at least once per 8 hours0.333 days <br />0.0476 weeks <br />0.011 months <br /> thereafter.

AND b.2 Demonstrate OPERABLE diesel generator is not inoperable due to common cause failure within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> or perform Surveillance Requirement 4.8.1.1.2.a.5 for the OPERABLE diesel generator within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br />. AND MILLSTONE - UNIT 3 3/4 8-1 Amendment No. ff, 77, Jfl, 210 0815 AUG t56 2kJ-4

ELECTRICAL POWER SYSILMS LIMITING CONDITION FOR OPERATION ACTION (continued) Inoperable Equipment Required Action

b. One diesel b.3 Verify all required systems, subsystems, generator trains, components, and devices that depend on the remaining OPERABLE diesel generator as a source of emergency power are OPERABLE, and the steam-driven auxiliary feedwater pump is OPERABLE (MODES 1, 2, and 3 only). If these conditions are not satisfied within 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br />, be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

AND b.4 (Applicable only if the 14 day allowed outage time specified in Action Statement b.5 is to be used). Verify the required Millstone Unit No. 2 diesel generator(s) is/are OPERABLE and the Millstone Unit No. 3 SBO diesel generator is available within 1 hour prior to or after entering this condition, and at least once per 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> thereafter. Restore any inoperable required Millstone Unit No. 2 diesel generator to OPERABLE status and/or Millstone Unit No. 3 SBO diesel generator to available status within 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />. AND b.5 Restore the inoperable diesel generator to OPERABLE status within 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> (within 14 days if Action Statement b.4 is met) or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

c. One offsite

c. One offsite c.1 Perform Surveillance Requirement circuit 4.8.1.1.1.a for remaining offsite circuit within 1 hour and at least once per 8 hours0.333 days <br />0.0476 weeks <br />0.011 months <br /> thereafter.

AND AND One diesel generator c.2 Demonstrate OPERABLE diesel generator is not inoperable due to common cause failure within 8 hours0.333 days <br />0.0476 weeks <br />0.011 months <br /> or perform Surveillance Requirement 4.8.1.1.2.a.5 for the OPERABLE diesel generator within 8 hours0.333 days <br />0.0476 weeks <br />0.011 months <br />. AND MILLSTONE - UNIT 3 3/4 8-2 Amendment No. 210 0815 AUG 26 2X

LLU - L.% IX hnL. A a Unl1 . I v a ._. LIMITING CONDITION FOR OPERATION ACTION (continued) Inoperable Equipment Required Action

c. One offsite c.3 Verify all required systems, subsystems, circuit trains, components, and devices that depend on the remaining OPERABLE diesel generator AND as a source of emergency power are OPERABLE, and the steam-driven auxiliary One diesel feedwater pump is OPERABLE (MODES 1, 2, and generator 3 only). If these conditions are not satisfied within 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br />, be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

AND c.4 Restore one inoperable A.C. source to OPERABLE status within 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />. AND c.5 Restore remaining inoperable A.C. source to OPERABLE status following the time requirements of Action Statements a. or b. above based on the initial loss of the remaining inoperable A.C. source.

d. Two offsite d.1 Restore one of the inoperable offsite circuits sources to OPERABLE status within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />.

AND d.2 Following restoration of one offsite source, restore remaining inoperable offsite source to OPERABLE status following the time requirements of Action Statement

a. above based on the initial loss of the remaining inoperable offsite source.

e. Two diesel e.1 Perform Surveillance Requirement generators 4.8.1.1.1.a for the offsite circuits within 1 hour and at least once per 8 hours0.333 days <br />0.0476 weeks <br />0.011 months <br /> thereafter.

AND MILLSTONE - UNIT 3 3/4 8-3 Amendment No. 210 0815 AUG 2 6 2002

LLLItKIUAL FUWLK -blbItM3 LIMITING CONDITION FOR OPERATION ACTION (continued) Inoperable Equipment Required Action

e. Two diesel e.2 Restore one of the inoperable diesel generators generators to OPERABLE status within 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

AND e.3 Following restoration of one diesel generator, restore remaining inoperable diesel generator to OPERABLE status following the time requirements of Action Statement b. above based on the initial loss of the remaining inoperable diesel generator. SURVEILLANCE REQUIREMENTS 4.8.1.1.1 Each of the above required independent circuits between the offsite transmission network and the Onsite Class 1E Distribution System shall be:

a. Determined OPERABLE at least once per 7 days by verifying correct breaker alignments, indicated power availability, and

b. Demonstrated OPERABLE at least once per 18 months during shutdown by transferring (manually and automatically) unit power supply from the normal circuit to the alternate circuit.

4.8.1.1.2 Each diesel generator shall be demonstrated OPERABLE:*

a. At least once per 31 days on a STAGGERED TEST BASIS by:

1) Verifying the fuel level in the day tank,

2) Verifying the fuel level in the fuel storage tank,

3) Verifying the fuel transfer pump starts and transfers fuel from the storage system to the day tank,

4) Verifying the lubricating oil inventory in storage,

5) Verifying the diesel starts from standby conditions and achieves generator voltage and frequency at 4160 + 420 volts and 60 + 0.8 Hz. The diesel generator shall be started for this test by using one of the following signals:

a) Manual, or

• All planned starts for the purpose of these surveillances may be preceded by an engine prelube period.

MILLSTONE - UNIT 3 3/4 8-3a Amendment No. 79, ff, Jfi, IYO, 210 0815 AUG 26 2002

_Ji __ Xt < r U6Li )1 Z11 LiPL SURVEILLANCE REQUIREMENTS (Continued) b) Simulated loss-of-offsite power by itself, or C) Simulated loss-of-offsite power in conjunction with an ESF Actuation test signal, or d) An ESF Actuation test signal by itself.

6) Verifying the generator is synchronized and gradually loaded in accordance with the manufacturer's recommendations between 4800-5000 kW* and operates with a load between 4800-5000 kW* for at least 60 minutes, and'

7) Verifying the diesel generator is aligned to provide standby power to the associated emergency busses.

b. At least once per 184 days by:

1) Verifying that the diesel generator starts from standby conditions and attains generator voltage and frequency of 4160 + 420 volts and 60 + 0.8 Hz within 11 seconds after the; start signal.

2) Verifying the generator is synchronized to the associated emergency bus, loaded between 4800-5000 kW* in accordance with the manufacturer's recommendations, and operate with a load between 4800-5000 kW* for at least 60 minutes.

The diesel generator shall be started for this test using one of the signals in Surveillance Requirement 4.8.1.1.2.a.5. This test if it is performed so it coincides with the testing required by Surveiilance Requirement 4.8.1.1.2.a.5, may also serve to concurrently meet those requirements as well.

c. At least once per 31 days and after each operation of the diesel where the period of operation was greater than or equal to 1 hour by checking for and removing accumulated water from the day tank;

d. At least once per 31 days by checking for and removing accumulated water from the fuel oil storage tanks;

e. By sampling new fuel oil in accordance with ASTM-D4057 prior to addition to storage tanks and:

1) By verifying in accordance with the tests specified in ASTM-0975-81 prior to addition to the storage tanks that the sample has:

a) An API Gravity of within 0.3 degrees at 600F, or a specific gravity of within 0.0016 at 60/60OF, when compared to the supplier's certificate, or an absolute specific gravity at 60/60'F of greater than or equal to 0.83 but less than or equal to 0.89, or an API gravity of greater than or equal to 27 degrees but less than or equal to 39 degrees;

• The operating band is meant as guidance to avoid routine overloading of the diesel Momentary transients outside the load range shall not invalidate the test.

MILLSTONE - UNIT 3 3/4 8-4 Amendment No. 9, PI, Jl. fl7, 0744 194,

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) b) A kinematic viscosity at 40"C of greater than or equal to 1.9 centistokes, but less than or equal to 4.1 centistokes (alternatively, Saybolt viscosity, SUS at IOOF of greater than or equal to 32.6, but less than or equal to 40.1) if gravity was not determined by comparison with the supplier's certification; c) A flash point equal to or greater than 125'F; and d) Water and sediment less than 0.05 percent by volume when tested in accordance with ASTM-01796-83.

2) By verifying within 30 days of obtaining the sample that.the other properties specified in Table I of ASTM-D975-81 are met when tested in accordance with ASTM-0975-81 except that:

1) the cetane index shall be determined in accordance with SM-B976 (this test is anappropriate approximation for cetane number as stated in ASTM-D915-81 (Note El), and (2) the analysis for sulfur may be performed in accordance with ASTM-D1552-79, ASTM-D2622-82 or ASTM-04294.83.

f. At least once every 31 days by obtaining a sample of fuel-oil in accordance with ASTM-D2276-78, and verifying that total particulate contamination is less than 10 mg/liter when checked in accordance with ASTM-D2276-78, Method A;

g. At least once per 18 months, during shutdown, by:

1) DELETED

2) Verifying the generator capability to reject a load of greater than or equal to 595 kW while maintaining voltage at 4160 + 420 volts and frequency at 60 + 3 Hz;

3) Verifying the.generator capability to reject a load of 4986 kW without tripping. The generator voltage shall not exceed 5000 volts during and 4784 volts following the load rejection;

4) Simulating a loss-of-offsite power by itself, and:

a) Verifying deenergization of the emergency busses and load shedding from the emergency busses, and b) Verifying the diesel starts from standby conditions on the auto-start signal, energizes the emergency busses with permanently connected loads within 11 seconds, energizes the auto-connected shutdown loads through the load sequencer and operates for greater than or equal to 5 minutes while its generator is loaded with the shutdown loads. After energization, the steady-state voltage and frequency of the emergency busses shall De maintained at 4160 + 420 volts and 60 + 0.8 Hz during this test. MILLSTONE - UNTT 3 3/4 8-5 Anit-idment No. i, X0, i, 7fl, XP, a.Yrk Y'T . I

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

5) Verifying that on an ESF Actuation test signal, without loss-of-offsite power, the diesel generator starts from standby conditions on the auto-start signal and operates on standby for greater than or equal to 5 minutes. The generator voltage and frequency shall be 4160 + 420 volts and 60 + 0.8 Hz within 11 seconds after the auto-stirt signal; the steady-state generator voltage and frequency shall be maintained within these limits during this test;

6) Simulating a loss-of-offsite power in conjunction with an ESF Actuation test signal, and:

4 a) . Verifying deenergization of the emergency busses and load shedding from the emergency busses; b) Verifying the diesel starts from standby conditions on the auto-start signal, energizes the emergency busses with permanently connected loads within 11 seconds, energizes the auto-connected emergency (accident) loads- through the load sequencer and operates for greater than or equal to 5 minutes while its generator is loaded with the emergency loads. After energization, the steady-state voltage and frequency of the emergency busses shall be maintained at 4160 + 420 volts and 60 + 0.8 Hz during this test; and c) Verifying that all automatic diesel generator trips, except engine overspeed, lube oil pressure low (2 of 3 logic) and generator differential, are automatically bypassed upon loss of voltage on the emergency bus concurrent with a Safety Injection Actuation signal.

7) DELETED MILLSTONE - UNIT 3 071 4 3/4 8- 6 Amendment No. 0, 94, 117, P77, l 154

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

8) Verifying that the auto-connected loads to each diesel generator do not exceed the 2000-hour rating of 5335 kW;

9) Verifying the diesel generator's capability to:

a) Synchronize with the offsite power source while the-generator is loaded with its emergency loads upon a simulated restoration of offsite power, b) Transfer its loads to the offsite power source, and c) Be restored to its standby status.

10) Verifying that with the diesel generator operating in a test-mode, connected to its bus, a simulated Safety Injection signal overrides the test mode by: (1) returning the diesel generator to standby operation, and (2) automatically energizing the emergency loads with offsite power;

11) DELETED I

12) Verifying that the automatic load sequence timer is OPERABLE with the interval between each load block within +/- 10% of its design interval; and

13) DELETED

n. At least once per 10 years or after any modifications which could affect diesel generator interdependence by starting both diesel generators simultaneously from standby conditions, during shutdown, and I verifying that both diesel generators achieve generator voltage and frequency at 4160 +/- 420 volts and 60 +/- 0.8 Hz in less than or equal to 11 seconds; and

i. At least once per 10 years by draining each fuel oil storage tank, removing the accumulated sediment and cleaning the tank using a sodium hypochlorite solution.

MILLSTONE - UNIT 3 3/4 8-7 M Amendment No. f, y P0 7 M, 0 744 177, 194 I

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

j. At least once per 18 months by verifying the diesel generator operates for at least 24 hours1 days <br />0.143 weeks <br />0.0329 months <br />. During the first 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> of this test, the diesel generator shall be loaded between 5400-5500 kW* and during the remaining 22 hours0.917 days <br />0.131 weeks <br />0.0301 months <br /> of this test, the diesel generator shall be loaded between 4800-5000 kW*. The generator voltage and frequency shall be 4160 + 420 volts and 60 + 0.8 Hz within 11 seconds after the start signaT; the steady-state generator voltage and frequency shall be maintained within these limits during this test.** Within 5 minutes after completing this 24-hour test, perform Specification 4.8.1.1.2.a.5) excluding the requirement to start the diesel from standy conditions.***

     -k. At least once per 18 months by verifying that the fuel transfer pump transfers fuel from each fuel storage tank to the day tank of each diesel via the installed cross-connection lines.

1. At least once per 18 months by verifying that the following diesel generator lockout features prevent diesel generator start-ng:

1) Engine overspeed,

2) Lube oil pressure low (2 of 3 logic),

3) Generator differential, and

4) Emergency stop.

• The o erating band is meant as guidance to avoid routine overloading of the diesel. Momentary transients outside the load range shall not invalidate the test.
  • Diesel generator loadings may include gradual loading as recommended by the manufacturer.
• If Surveillance Requirement 4.8.1.1.2.a.5) is not satisfactorily completed, it is not necessary to repeat the preceding 24-hour test. Instead, the diesel generator may be operated between 4800-5000 kW for 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> or until operating temperature has stabilized.

MILLSTONE - UNIT 3 3/4 B-8 Amendment No. 19, fo,

-7,4                                                                      194

This page intentionally left blank. MILLSTONE - UNIT 3 0744 3/4 8-9 Amendment No. f9, 194 l i , I

A. C. SOURCES SHUTDOWN LIMITING CONDITION FOR OPERATION 3.8.1.2 As a minimum, the following A. C. electrical power sources shall be OPERABLE:

a. One circuit between the offsite transmission network and the Onsite Class 1E Distribution System, and

b. One diesel generator with:

1) A day tank containing a minimum volume of 278 gallons of fuel,

2) A fuel storage system containing a minimum volume of 32,760 gallons of fuel,

3) A fuel transfer pump,

4) Lubricating oil storage containing a minimum total volume of 280 gallons of lubricating oil, and

5) Capability to transfer lubricating oil from storage to the diesel generator unit.

APPLICABILITY: MODES 5 and 6. ACTION: With less than the above minimum required A. C. electrical power sources OPERABLE, immediately suspend all operations involving CORE ALTERATIONS, positive reactivity changes, movement of irradiated fuel, crane operation with loads over the fuel storage pool, or operation with a potential for draining the reactor vessel; initiate corrective action to restore the required sources to OPERABLE status as soon as possible. SURVEILLANCE REQUIREMENT 4.8.1.2 The above required A.C. electrical power sources shall be demonstrated OPERABLE by the performance of each of the requirements of Specifications 4.8.1.1.1, 4.8.1.1.2 (except for Specifications 4.8.1.1.2.a.6 and 4.8.1.1.2.b.2). MILLSTONE - UNIT 3 3/4 8-10 Amendment No. 79, F;, j, J09, 1 9 4 0 7St ,,,n

ELECTRICAL POWER SYSTEMS 3/4.8.2 D.C. SOURCES OPERATING LIMITING CONDITION FOR OPERATION 3.8.2.1 As a minimum, the following D.C. electrical sources shall be OPERABLE:

a. 125-volt Battery Bank 301A-1, and an associated full capacity charger,

b. 125-volt Battery Bank 301A-2, and an associated full capacity charger,

c. 125-volt Battery Bank 301B-1 and an associated full capacity charger, and

d. 125-volt Battery Bank 301B-2 and an associated full capacity charger.

APPLICABILITY: MODES 1, 2, 3, and 4. ACTION:

a. With either Battery Bank 301A-1 or 301B-1, and/or one of the required full capacity chargers inoperable, restore the inoperable battery bank and/or full capacity charger to OPERABLE status within 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

b. With either Battery Bank 301A-2 or 301B-2 inoperable, and/or one of the required full capacity chargers inoperable, restore the inoper-able battery bank and/or full capacity charger to OPERABLE status within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

1 SURVEILLANCE REQUIREMENTS 4.8.2.1 Each'125-volt battery bank and charger shall be demonstrated OPERABLE:

a. At least once per 7 days by verifying that.:

1) The parameters in Table 4.8-2a meet the Category A limits, and

2) The total battery terminal voltage is greater than or equal to 129 volts on float charge.

MILLSTONE - UNIT 3 3/4 8-11 Amendment No. 64 AO '4 MAR 9 1992

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

b. At least once per 92 days and within 7 days after a battery discharge with battery terminal voltage below 110 volts, or battery overcharge with battery terminal voltage above 150 volts, by verify-ing that:

1) The parameters in Table 4.8-2a meet the Category B limits,

2) There is no visible corrosion at either terminals or connec-tors, or the connection resistance of these items is less than 150 x 10i ohm, and

3) The average electrolyte temperature of six connected cells is above 60EF.

c. At least once per 18 months by verifying that:

1) The cells, cell plates, and battery racks show no visual indication of physical damage or abnormal deterioration,

2) The cell-to-cell and terminal connections are clean, tight, and coated with anticorrosion material,

3) The resistance of each cell-to-cell and terminal connection is less than or equal to 150 x 106 ohm, and

4) Each battery charger will supply at least the amperage indi-cated in Table 4.8-2b at greater than or equal to 132 volts for at least 24 hours1 days <br />0.143 weeks <br />0.0329 months <br />.

d. At least once per 18 months, during shutdown, by verifying that the battery capacity is adequate to supply and maintain in OPERABLE status all of the actual or simulated emergency loads for the design duty cycle when the battery is subjected to a battery service test;

e. At least once per 60 months, during shutdown, by verifying that the battery capacity is at least 80% of the manufacturer's rating when subjected to a performance discharge test. Once per 60-month interval this performance discharge test may be performed in lieu of the battery service test required by Specification 4.8.2.1d.; and

f. At least once per 18 months, during shutdown, by giving performance discharge tests of battery capacity to any battery that shows signs of degradation or has reached 85% of the service life expected for the application. Degradation is indicated when the battery capacity drops more than 10% of rated capacity from its average on previous performance tests, or is below 90% of the manufacturer's rating.

MILLSTONE - UNIT 3 0620 3/4 8-12 Amendment No. If, 7y, 7Pp, 149

TABLE 4.8-2a BATTERY SURVEILLANCE REQUIREMENTS CATEGORY A(') CATEGORY B(2) PARAMETER LIMITS FOR EACH LIMITS FOR EACH ALLOWABLE(3) DESIGNATED PILOT CONNECTED CELL VALUE FOR EACH CELL CONNECTED CELL Electrolyte >Minimum level >Minimum level Above top of Level indication mark, indication mark, plates, and and < ki above and < 3/40 above not overflowing maximum level maximum level indication mark indication mark Float Voltage 2 2.13 volts > 2.13 volts(6) > 2.07 volts Not more than 0.020 below the average of all Specific > 1.195 connected cells Gravity(4) > 1.200(5) Average of all Average of all connected cells connected cells

                                            > 1.205             > 1.195(5)

TABLE NOTATIONS (1) For any Category A parameter(s) outside the limit(s) shown, the.battery may be considered OPERABLE provided that within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> all the Cate-gory B measurements are taken and found to be within their allowable values, and provided all Category A and B parameter(s) are restored to within limits within the next 6 days. (2) For any Category B parameter(s) outside the limit(s) shown, the battery may be considered OPERABLE provided that the Category B parameters are within their allowable values and provided the Category B parameter(s) are restored to within limits within 7 days. (3) Any Category B parameter not within its allowable value indicates an inoperable battery. (4) Corrected for electrolyte temperature and level. (5) Or battery charging current is less than 2 amps when on charge. (6) Corrected for average electrolyte temperature. MILLSTONE - UNIT 3 3/4 8-13 Amendment No. 64 0054 MAR 9 1992

TABLE 4.8-2b BATTERY CHARGER CAPACITY CHARGER AMPERAGE 3OA-1 200 301A-2 50 301A-3 200 301B-1 200 301B-2 50 301B-3 200 MILLSTONE - UNIT 3 3/4 8-14 Amendment No. 64 0054 MAR 9 1992

ELECTRICAL POWER SYSTEMS D. C. SOURCES SHUTDOWN LIMITING CONDITION FOR OPERATION 3.8.2.2 As a minimum, one train (A or B) of batteries and their associated full capacity chargers shall be OPERABLE:

a. Train - 'A' consisting of:

1) Battery Bank 301A-1 and a full capacity battery charger, and

2) Battery Bank 301A-2 and a full capacity battery charger.

OR

b. Train - "Bo consisting of:

1) Battery Bank 301B-1 and a full capacity battery charger, and

2) Battery Bank 301B-2 and a full capacity battery charger.

APPLICABILIT: MODES S and 6. ACTION: With the required train inoperable, immediately suspend all operations I involving CORE ALTERATIONS, positive reactivity changes, movement of irradiated fuel; crane operation with loads over the fuel storage pool, or operation with a potential for draining the reactor vessel; Initiate corrective action to restore the required train to OPERABLE status as soon as I possible. SURVEILLANCE REQUIREMENTS 4.8.2.2 The above required train shall be demonstrated OPERABLE in accordance with Specification 4.8.2.1. I MILLSTONE - UNIT 3 3/4 8-15 Amendment No. pa. Ff. IspF 146 050 AI rjn r, I .. n

ELECTRICAL POWER SYSTEMS 3/4.8.3 ONSITE POWER DISTRIBUTION OPERATING LIMITING CONDITION FOR OPERATION 3.8.3.1 The following electrical busses shall be OPERABLE in the specified manner: I

a. Train A A.C. Emergency Busses consisting of:

1) 4160-Volt Emergency Bus #34C, and

2) 480-Volt Emergency Bus #32R, 32S, 32T, and 32Y.

b. Train B A.C. Emergency Busses consisting of:

1) 4160-Volt Emergency Bus #34D, and

2) 480-Volt Emergency Bus #32U, 32V, 32W, and 32X.

c. 120-Volt A.C. Vital Bus #VIAC-l energized from its associated inverter connected to D.C. Bus #301A-1*,

d. 120-Volt A.C. Vital Bus #VIAC-2 energized from its associated inverter connected to D.C. Bus #301B-1*,

e. 120-Volt A.C. Vital Bus #VIAC-3 energized from its associated inverter connected to D.C. Bus #301A-2*,

f. 120-Volt A.C. Vital Bus #VIAC-4 energized from its associated inverter connected to D.C. Bus #301B-2*,

g. 125-Volt D.C. Bus #301A-1 energized from Battery Bank #301A-1,

h. 125-Volt D.C. Bus #301A-2 energized from Battery Bank #301A-2,

i. 125-Volt D.C. Bus #301B-1 energized from Battery Bank #301B-1, and

j. 125-Volt D.C. Bus #301B-2 energized from Battery Bank #301B-2.

• Two inverters may be disconnected from their D.C. bus for up to 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> as necessary, for the purpose of performing an equalizing charge on their associated battery bank provided: (1) their vital busses are energized, and (2) the vital busses associated with the other battery bank are energized from their associated inverters and connected to their associated D.C. bus.

MILLSTONE - UNIT 3 3/4 8-16 Amendment No. 64,220

ELECTRICAL POWER SYSTEMS LIMITING CONDITION FOR OPERATION APPLICABILITY: MODES 1, 2, 3, and 4. ACTION:

a. With one of the required trains of A.C. emergency busses not OPERABLE, restore the inoperable train to OPERABLE status within 8 hours0.333 days <br />0.0476 weeks <br />0.011 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

b. With one A.C. vital bus either not energized from its associated inverter, or with the in-verter not connected to its associated D.C. bus: (1) reenergize the A.C. vital bus within 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />; and (2) reenergize the A.C.

vital bus from its associated inverter connected to its associated D.C. bus within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

c. With one D.C. bus not energized from its associated battery bank, reenergize the D.C. bus from its associated battery bank within 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> or be in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

SURVEILLANCE REQUIREMENTS 4.8.3.1 The specified busses shall be determined OPERABLE in the specified manner at least once per 7 days by verifying correct breaker alignment and indicated voltage on the busses. MILLSTONE - UNIT 3 3/4 8-17 Amendment No.-64, 220

ONSITE POWER DISTRIBUTION SHUTDOWN LIMITING CONDITION FOR OPERATION 3.8.3.2 As a minimum, one train (A or B) of the following electrical busses shall be OPERABLE:

a. Train - 'A' consisting of:

1) One 4160 volt AC Emergency Bus 134C, and

2) Four 480 volt AC Emergency Busses 132R, 132S, #32T, 132Y, and

3) Two 120 volt AC Vital Busses consisting of:

a) Bus IVIAC-1 energized from Inverter #INV-1 connected to DC Bus 13OIA-1, and b) Bus #VIAC-3 energized from Inverter #INV-3 connected to DC Bus #301A-2, and

4) Two 125 volt DC Busses consisting of:

a) Bus 1301A-1 energized from Battery Bank {301A-1, and b) Bus 1301A-2 energized from Battery Bank #301A-2. OR

b. Train - "BE consisting of

1) One 4160 volt AC Emergency Bus #34D, andA(

2) Four 480 volt AC Emergency Busses #32U, #32V, #32W, f32X, and

3) Two 120 volt AC Vital Busses consisting of:

a) Bus #VIAC-2 energized from Inverter VINV-2 connected to DC Bus #301B-1, and b) Bus #VIAC-4 energized from Inverter #INV-4 connected to DC Bus #301B-2, and

4) Two 125 volt DC Busses consisting of:

a) Bus #301B-1 energized from Battery Bank #301B-1, and b) Bus #301B-2 energized from Battery Bank #301B-2. APPLICABILITY: MODES S and 6. ACTION: With any of the above required electrical busses not energized in the required manner, immediately suspend all operations involving CORE ALTERATIONS, positive reactivity changes, movement of irradiated fuel, crane operation with loads over the fuel storage pool, or operations with a potential for draining the reactor vessel, initiate corrective action to energize the required electrical busses in the specified manner as soon as possible. MILLSTONE - UNIT 3 3/4 8-18 Amendment No. 79, by, ;q?, 1fi,177 0639

ELECTRICAL POWER SYSTEMS ONSITE POWER DISTRIBUTION SURVEILLANCE REQUIREMENTS 4.8.3.2 The specified busses shall be determined energized in the required manner at least once per 7 days by verifying correct breaker alignment and indicated voltage on the busses. 0ILLSTONE - UNIT 3 3/4 8-18a, Amendment No. 146 1 0601

THIS PAGE INTENTIONALLY LEFT BLANK MILLSTONE - UNIT 3 314 B-19 Amendment No. lp, J7, 1s, 192 06i63 a;. I I .,1

THIS PAGE INTENTIONALLY LEFT BLANK MILLSTONE - UNIT 3 0e83 3/4 8-20 Amendment No. fl.f JfJl, 192

THIS PAGE INTENTIONALLY LEFT BLANK 0ILLSTONE - UNIT 3 3/4 8-21 Amendment No. Z7, fi, 192 0706 V1 n , . ', o w - . . I . .

THIS PAGE INTENTIONALLY LEFT BLANK MILLSTONE - UNIT 3 3/4 8-22 Amendment No. IF, ff, aft, 192 0706

3/4.9 REFUELING OPERATIONS 3/4.9.1 BORON CONCENTRATION LIMITING CONDITION FOR OPERATION 3.9.1.1 The boron concentration of all filled portions of the Reactor Coolant System and the refueling canal shall be maintained sufficient to ensure that the more restrictive of the following reactivity conditions is met; either:

a. A Keff Of 0. 95 or less, or

b. A boron concentration of greater than or equal to the limit specified in the CORE OPERATING LIMITS REPORT (COLR).

Additionally, the CVCS valves of Specification 4.1.1.2.2 shall be closed and secured in position. APPLICABILITY: MODE 6.* ACTION:

a. With the requirements of the above specification not satisfied, immediately suspend all operations involving CORE ALTERATIONS or positive reactivity changes and initiate and continue boration at greater than or equal to 33 gpm of a solution containing greater than or equal to 6600 ppm boron or its equivalent until Keff is reduced to less than or equal to 0.95 or the boron concentration is restored to greater than or equal to the limit specified in the COLR, whichever is the more restrictive.

b. With any of the CVCS valves of Specification 4.1.1.2.2 not closed"* and secured in position, immediately close and secure the valves.

SURVEILLANCE REQUIREMENTS 4.9.1 .1.1 The more restrictive of the above two reactivity conditions shall be determined prior to:

a. Removing or unbolting the reactor vessel head, and

b. Withdrawal of any full-length control rod in excess of 3 feet from its fully inserted position within the reactor vessel.

4.9.1.1.2 The boron concentration of the Reactor Coolant System and the refueling cavity shall be determined by chemical analysis at least once per 72 hours3 days <br />0.429 weeks <br />0.0986 months <br />. 4.9.1.1.3 The CVCS valves of Specification 4.1.1.2.2 shall be verified closed and locked at least once per 31 days.

• The reactor shall be maintained in MODE 6 whenever fuel is in the reactor vessel with the vessel head closure bolts less than fully tensioned or with the head removed.

**  Except those opened under administrative control.

MILLSTONE - UNIT 3 3/4 9-1 Amendment No. , 60, 99, 4-3, 23, 218

REFUELING OPERATIONS BORON CONCENTRATION LIMITING CONDITION FOR OPERATION 3.9.1.2 The soluble boron concentration of the Spent Fuel Pool shall be greater than or equal to 800 ppm. I Applicability Whenever fuel assemblies are in the spent fuel pool. Action

a. With the boron concentration less than 800 ppm, initiate action to bring the boron concentration in the fuel pool to at least 800 ppm within 72 hours3 days <br />0.429 weeks <br />0.0986 months <br />, and

b. With the boron concentration less than 800 ppm, suspend the movement of all fuel assemblies within the spent fuel pool and loads over the spent fuel racks.

SURVEILLANCE REQUIREMENTS 4.9.1.2 Verify that the boron concentration in the fuel pool is greater than or equal to 800 ppm every 7 days. MILLSTONE - UNIT 3 3/4 9-1a Amendment No. 77, Ad, oy, 203 0834

REFUELING OPERATIONS 3/4.9.2 INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.9.2 Two Source Range Neutron Flux Monitors shall be OPERABLE with continuous visual indication in the control room, and one with audible indication-in the containment and control room. APPLICABILITY: MODE 6. ACTION:

a. With one of the above required monitors inoperable immediately suspend all operations involving CORE ALTERATIONS or positive reactivity changes.

I

b. With both of the above required monitors inoperable determine the boron concentration of the Reactor Coolant System within 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> and at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> thereafter.

SURVEILLANCE REQUIREMENTS 4.9.2 Each Source Range Neutron Flux Monitor shall be demonstrated OPERABLE by performance of:

a. A CHANNEL CHECK and verification of audible counts at least once per I 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />,

b. A CHANNEL CALIBRATION at least once per 18 months.* I

• Neutron detectors are excluded from CHANNEL CALIBRATION. I MILLSTONE - UNIT 3 3/4 9-2 Amendment No. 707- 203 0729

REFUELING OPERATIONS 3/4.9.3 DECAY TIME LIMITING CONDITION FOR OPERATION 3.9.3 The reactor shall be subcritical for at least 100 hours4.167 days <br />0.595 weeks <br />0.137 months <br />. APPLICABILITY: During movement of irradiated fuel in the reactor vessel. ACTION: With the reactor subcritical for less than 100 hours4.167 days <br />0.595 weeks <br />0.137 months <br />, suspend all operations involving movement of irradiated fuel in the reactor vessel. SURVEILLANCE REQUIREMENTS 4.9.3 The reactor shall be determined to have been subcritical for at least 100 hours4.167 days <br />0.595 weeks <br />0.137 months <br /> by verification of the date and time of subcriticality prior to movement of irradiated fuel in the reactor vessel. MILLSTONE - UNIT 3 3/4 9-3

REFUELING OPERATIONS 3/4.9.4 CONTAINMENT BUILDING PENETRATIONS LIMITING CONDITION FOR OPERATION 3.9.4 The containment building penetrations shall be in the following status:

a. The equipment access hatch shall be either:

I. closed and held in place by a minimum of four bolts, or

2. open under administrative control

• and capable of being closed and held in place by a minimum of four bolts,

b. A personnel access hatch shall be either

1. closed by one personnel access hatch door, or

2. capable of being closed by an OPERABLE personnel access hatch door, under administrative control,* and

c. Each penetration providing direct access from the containment atmosphere to the outside atmosphere shall be either:

1. Closed by an isolation valve, blind flange, or manual valve, or

2. Be capable of being closed under administrative control.*

APPLICABILITY: During movement of fuel within the containment building. ACTION: With the requirements of the above specification not satisfied, immediately suspend all operations involving movement of fuel in the containment building. SURVEILLANCE REQUIREMENTS 4.9.4.a Verify each required containment penetrations is in the required status at least once per 7 days. 4.9.4.b DELETED

• Administrative controls shall ensure that appropriate personnel are aware that the equipment access hatch penetration, personnel access hatch doors and/or other containment penetrations are open, and that a specific individual(s) is designated and available to close the equipment access hatch penetration, a personnel access hatch door and/or other containment penetrations within 30 minutes if a fuel handling accident occurs. Any obstructions (e.g. cables and hoses) that could prevent closure of the equipment access hatch penetration, a personnel access hatch door and/or other containment penetrations must be capable of being quickly removed.

MILLSTONE - UNIT 3 3/4 9-4 Amendment No. 20, 219

THIS PAGE INTENTIONALLY LEFT BLANK JLLSTONE - UNIT 3 3/4 9-5 Amendment No, 225

THIS PAGE INTENTIONALLY LEFT BLANK AILLSTONE - UNIT 3 3/4 9-6 Amendment No. 225

THIS PAGE INqTENONALLY LEFT BLANK .LLSTONE - UNIT 3 314 9-7 Amendment No. 9, 4, 225

REFUELING OPERATIONS 3/4.9.8 RESIDUAL HEAT REMOVAL AND COOLANT CIRCULATION HIGH WATER LEVEL LIMITING CONDITION FOR OPERATION 3.9.8.1 At least one residual heat removal (RHR) loop shall be OPERABLE and in operation.* APPLICABILITY: MODE 6, when the water level above the top of the reactor vessel flange is greater than or equal to 23 feet. ACTION: With no RHR loop OPERABLE or in operation, suspend all operations involving a reduction in boron concentration of the Reactor Coolant System and suspend loading irradiated fuel assemblies in the core and immediately initiate corrective action to return the required RHR loop to OPERABLE and operating status as soon as possible. Close all containment penetrations providing direct access from the containment atmosphere to the outside atmosphere within 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />. I SURVEILLANCE REQUIREMENTS 4.9.8.1 At least one RHR loop shall be verified in operation and circulating reactor coolant at a flow rate of greater than or equal to 2800 gpm at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />.

• The RHR loop may be removed from operation for up to 1 hour per 8-hour period, provided no operations are permitted that could cause dilution of the RCS boron concentration.

I MILLSTONE - UNIT 3 3/4 9-8 Amendment No.107 0286 a,1, 2 .;,8,5 tI

REFUELING OPERATIONS LOW WATER LEVEL LIMITING CONDITION FOR OPERATION 3.9.8.2 Two independent residual heat removal (RHR) loops shall be OPERABLE, and at least one RHR loop shall be in operation.* APPLICABILITY: MODE 6, when the water level above the top of the reactor vessel flange is less than 23 feet. ACTION:

a. With less than the required RHR loops OPERABLE, immediately initiate corrective action to return the required RHR loops to OPERABLE status, or to establish greater than or equal to 23 feet of water above the reactor vessel flange, as soon as possible.

b. With no RHR loop in operation, suspend all operations involving a reduction in boron concentration of the Reactor Coolant System and immediately initiate corrective action to return the required RHR loop to operation. Close all containment penetrations providing direct access from the containment atmosphere to the outside atmosphere within 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />.

SURVEILLANCE REQUIREMENTS 4.9.8.2 At least one RHR loop shall be verified in operation and circulating reactor coolant at a flow rate of greater than or equal to 2800 gpm at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />.

• The RHR loop may be removed from operation for up to 1 hour per 8-hour period, provided no operations are permitted that could cause dilution of the RCS boron concentration.

MILLSTONE - UNIT 3 3/4 9-9 Amendment No. 107 0280 APR 1 2 1995

THIS PAGE INTENTIONALLY LEFI BLANK I 'STONE - UNlr 3 3/4 9-10 Amendment No. . i20, 219

REFUELING OPERATIONS 3/4.9.10 WATER LEVEL - REACTOR VESSEL LIMITING CONDITION FOR OPERATION 3.9.10 At least 23 feet of water shall be maintained over the top of the reactor vessel flange. APPLICABILITY: During movement of fuel assemblies or control rods within the containment when either the fuel assemblies being moved or the fuel assemblies seated within the reactor vessel are irradiated while in MODE 6. ACTION: With the requirements of the above specification not satisfied, suspend all operations involving movement of fuel assemblies or control rods within the reactor vessel. SURVEILLANCE REQUIREMENTS 4.9.10 The water level shall be determined to be at least its minimum required depth at least once per 24 hours1 days <br />0.143 weeks <br />0.0329 months <br />. MILLSTONE - UNIT 3 3/4 9-11 Amendment No.203 0835

REFUELING OPERATIONS 3/4.9.11 WATER LEVEL - STORAGE POOL LIMITING CONDITION FOR OPERATION 3.9.11 At least 23 feet of water shall be maintained over the top of irradiated fuel assemblies seated in the storage racks. APPLICABILITY: Whenever irradiated fuel assemblies are in the storage pool. ACTION:

a. With the requirements of the above specification not satisfied, suspend all movement of fuel assemblies and crane operations with loads in the fuel storage areas and restore the water level to within its limit within 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />.

b. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REOUIREMENTS I. 4.9.11 The water level in the storage pool shall be determined to be at least its minimum required depth at least once per 7 days when irradiated fuel assemblies are in the fuel storage pool. MILLSTONE - UNIT 3 3/4 9-12 AMENDMENT NO. 57 OCT 2 5 1990

THIS PAGE INTENTIONALLY LEFT BLANK .LSTONE - UNIT 3 3/4 9-13 Amendment No. , 1, 415, i-, 4-n, 23, 06, 219

THIS PAGE INTENTIONALLY LEFT BLANK LSTONE - UNIT 3 3/4 9-14 Amendment No. 2 i4, +-384, i6, 219

THIS PAGE INTENTIONALLY LEFT BLANK ",LSTONE - UNIT 3 314 9-15 Amendment 4, 03, 219

REFUELING OPERATIONS 3/4.9.13 SPENT FUEL POOL - REACTIVITY LIMITING CONDITION FOR OPERATION 3.9.13 The Reactivity Condition of the Spent Fuel Pool shall be such that keff is less than or equal to 0.95 at all times.. APPLICABILITY: Whenever fuel assemblies are in the spent fuel pool. ACTION: With keff greater than 0.95:

a. Borate the Spent Fuel Pool until keff is less than or equal to 0.95, and

b. Initiate immediate action to move any fuel assembly which does not meet the requirements of Figures 3.9-1, 3.9-3 or 3.9-4, to a location for which that fuel assembly is allowed.

SURVEILLANCE REQUIREMENTS 4.9.13.1.1. Ensure that all fuel assemblies to be placed in Region 1

             '4-OUT-OF-4" fuel storage are within the enrichment and burnup limits of Figure 3.9-1 by checking the fuel assembly's design and burn-up documentation.

4.9.13.1.2. Ensure that all fuel assemblies to be placed in Region 2 fuel storage are within the enrichment and burnup limits of Figure 3.9-3 by checking the fuel assembly's design and burn-up documentation. 4.9.13.1.3. Ensure that all fuel assemblies to be placed in Region 3 fuel storage are within the enrichment, decay time, and burnup limits of Figure 3.9-4 by checking the fuel asssembly's design, decay time, and burn-up documentation. MILLSTONE - UNIT 3 3/4 9-16 Amendment No. bpy Aid, 189 0822

REFUELING OPERATIONS SPENT FUEL POOL - STORAGE PATTERN LIMITING CONDITION FOR OPERATION 3.9.14 Each STORAGE PATTERN of the Region 1 spent fuel pool racks shall I require that: --

a. Prior to storing fuel assemblies in the STORAGE PATTERN per Figure 3.9-2, the cell blocking device for the cell location must be installed.

b. Prior to removal of a cell blocking device from the cell location per Figure 3.9-2, the STORAGE PATTERN must be vacant of all stored fuel assemblies -

APPLICABILITY: Whenever fuel assemblies are in the spent fuel pool. ACTION: Take immediate action to comply with 3.9.14(a), (b). SURVEILLANCE REQUIREMENTS 4.9.14 Verify that 3.9.14 is satisfied with no fuel assemblies stored in the STORAGE PATTERN prior to installing and removing a cell blocking device in the spent fuel racks. MILLSTONE - UNIT 3 3/4 9-17 Amendment No. 1p, 189 0622

FIGURE 3.9-1 Minimum Fuel Assembly Burnup Versus Nominal Initial Enrichment for Region 1 4-OUT-OF-4 Fuel Storage Configuration 8 7 6 5 D. CL m U-3 2 1 0 +- 3.50 3.75 4.00 4.25 4.50 4.75 5.00 Initl Fuel Enrichment (w/o U-235) M4LLSTONE - UNIT 3 3/4 9-18 Amendment No. IX,189 0748

FIGURE 3.9-2 Region 1 3-OUT-OF-4 Storage Fuel Assembly Loading Schematic Region 2 or Region 14-OUT-OF-4 may be placed along this face This face must be along

                               -P-N-               H-         -On the wall of the spent fuel pool, or other Region I                                                 Region 2 or Region 1 4-OUT-OF-4 3-OUT-OF-4 storage                                          -      U mu may be placed along this face
                                    -    E -     U -     E
                          -       U
                          -       t1       -
                                    -      mim                      m This face must be along the wall of the spent fuel pool, or other Region 1 3-OUT-OF-4 storage Cell Blocker location Fuel Assembly Storage location MILLSTONE - UNIT 3                              3/4 9-19                       Amendment No. 7j, 189 0748 Et.;1 . 2,')3

FIGURE 3.9-3 Minimum Fuel Assembly Burnup Versus Nominal Initial Enrichment for Region 2 Storage Configuration 40 35. 30 25 I-10 C 20 z 15 10 5 0 2.0 2.5 3.0 3.5 4.0 4.5 5.0 Initial Fuel Enrichment ( wlo U-235) MILLSTONE - UNIT 3 3/4 9-20 Amendment Ho.189 0748

FIGURE 3.9-4 Minimum Fuel Assembly Burnup and Decay Time Versus Nominal Initial Enrichment for Region 3 Storage Configuration 60 50 40 -_ 0 0 year decay time 5 year decay time

     '  30  -_

a 10 year decay time m -- 20 year decay time AL 20 -- 10 2.00 2.50 3.00 3.50 4.00 4.50 5.00 Initial Fuel Enrichment ( wlo U-235 )

• MILLSTONE - UNIT 3 3/4 9-21 Amendment Ho.189 0748 , I  ! .

3/4.10 SPECIAL TEST EXCEPTIONS 314.10.1 SHUTDOWN MARGIN LINITING COND ITION FOR OPERATION 3.10.1 The SHUTDOWN MARGIN requirement of Specification 3.1.1.1 may be suspended for measurement.of control rod worth and SHUTDOWN MARGIN provided reactivity equivalent to at least the highest estimated control rod worth is available for trip insertion from OPERABLE control rod(s). APPLICABILI  : MODE 2. ACTION:

a. With any full-length control rod not fully inserted and with less than the above reactivity equivalent available for trip insertion, Imfediately initiate and continue boration at greater than or equal to 33 gpm of a solution containing greater than or equal to 6600 ppm boron or its equivalent until the SHUTDOWN MARGIN required by Specification 3.1.1.1 is restored.

I

b. With all full-length control rods fully inserted and the reactor subcritical by less than the above reactivity equivalent, Inmedi-ately initiate and continue boration at greater than or equal to 33 gpm of a solution containing greater than or equal to 6600 ppm boron or its equivalent until the SHUTDOWN MARGIN required by Specification 3.1.1.1 is restored.

SURVEILLANCE REQUIREMENTS 4.10.1.1 The position of each full-length control roa either partially or fully withdrawn shall be determined at least once per 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br />. 4.10.1.2 Each full-length control rod not fully inserted shall be demonstrated capable of full insertion when tripped from at least the 50% withdrawn position within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> prior to reducing the SHUTDOWN MARGIN to less than the limits of Specification 3.1.1.1. MILLSTONE - UNIT 3 3/4 10-1 Amendment No. 113 0312 MAY 1 7 1995

SPECIAL TEST EXCEPTIONS 3/4.10.2 GROUP HEIGHT. INSERTION, AND POWER DISTRIBUTION LIMITS ITMTTTNA CrNnTTTnN FnR nPFRATTnN 3.10.2.1 The group height, insertion, and power distribution limits of Specifications 3.1.3.1, 3.1.3.5, 3.1.3.6, 3.2.1.1, and 3.2.4 may be suspended during the performance of PHYSICS TESTS provided:

a. The THERMAL POWER is maintained less than or equal to 85% of RATED THERMAL POWER, and

b. The limits of Specifications 3.2.2.1 and 3.2.3.1 are maintained and determined at the frequencies specified in Specification 4.10.2.1.2 below.

APPLICABILITY: MODE 1. ACTION: With any of the limits of Specification 3.2.2.1 or 3.2.3.1 being exceeded while the requirements of Specifications 3.1.3.1, 3.1.3.5, 3.1.3.6, 3.2.1.1, and 3.2.4 are suspended, either:

a. Reduce THERMAL POWER sufficient to satisfy the ACTION requirements of Specifications 3.2.2.1 and 3.2.3.1, or

b. Be in HOT STANDBY within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />.

SIIRVFTI I ANrF PFQIITRFMFNTC 4.10.2.1.1 The THERMAL POWER shall be determined to be less than or equal to 85% of RATED THERMAL POWER at least once per hour during PHYSICS TESTS. 4.10.2.1.2 The Surveillance Requirements of the below listed specifications shall be performed at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> during PHYSICS TESTS:

a. Specifications 4.2.2.1.2 and 4.2.2.1.3, and

b. Specification 4.2.3.1.2.

MILLSTONE - UNIT 3 3/4 10-2 Amendment No- 217 0984

This page intentionally left blank. MILLSTONE - UNIT 3 3/4 10-3 Amnendment N°-217 0984

SPECIAL TEST EXCEPTIONS 3/4.10.3 PHYSICS TESTS LIMITING CONDITION FOR OPERATION 3.10.3 The limitations of Specifications 3.1.1.3, 3.1.1.4, 3.1.3.1, 3.1.3.5, and 3.1.3.6 may be suspended during the performance of PHYSICS TESTS provided:

a. The THERMAL POWER does not exceed 5% of RATED THERMAL POWER,

b. The Reactor Trip Setpoints on the OPERABLE Intermediate and Power Range channels are set at less than or equal to 25% of RATED THERMAL POWER, and

c. The Reactor Coolant System lowest operating loop temperature (Tav) is greater than or equal to 5410F.

APPLICABILITY: MODE 2. ACTION:

a. With the THERMAL POWER greater than 5% of RATED THERMAL POWER, immediately open the Reactor trip breakers.

b. With a Reactor Coolant System operating loop temperature (Tav) less than 541 0F, restore Tav to within its limit within 15 minutes or be in at least HOT STANDBY within the next 15 minutes.

SURVEILLANCE REQUIREMENTS 4.10.3.1 The THERMAL POWER shall be determined to be less than or equal to 5% of RATED THERMAL POWER at least once per hour during PHYSICS TESTS. 4.10.3.2 Each Intermediate and Power Range channel shall be subjected to an ANALOG CHANNEL OPERATIONAL TEST within 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> prior to initiating PHYSICS TESTS. 4.10.3.3 The Reactor Coolant System temperature (Tav) shall be determined to be greater than or equal to 541'F at least once per 30 minutes during PHYSICS TESTS. MILLSTONE - UNIT 3 3/4 10-4

SPECIAL TEST EXCEPTIONS 3/4.10.4 REACTOR COOLANT LOOPS LIMITING CONDITION FOR OPERATION 3.10.4 The limitations of Specification 3.4.1.1 may be suspended during the performance of STARTUP and PHYSICS TESTS provided:

a. The THERMAL POWER does not exceed the P-7 Interlock Setpoint, and

b. The Reactor Trip Setpoints on the OPERABLE Intermediate and Power R~ange channels are set less than or equal to 25% of RATED THERMAL POWER.

APPLICABILITY: During operation below the P-7 Interlock Setpoint. ACTION: With the THERMAL POWER greater than the P-7 Interlock Setpoint, immediately open the Reactor trip breakers. SURVEILLANCE REQUIREMENTS 4.10.4.1 The THERMAL POWER shall be determined to be less than P-7 Interlock Setpoint at least once per hour during STARTUP and PHYSICS TESTS. 4.10.4.2 Each Intermediate and Power Range channel, and P-7 Interlock shall be subjected to an ANALOG CHANNEL OPERATIONAL TEST within 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> prior to initiating STARTUP and PHYSICS TESTS. MILLSTONE - UNIT 3 3/4 10- 5

THIS PAGE INTENTIONALLY LEFT BLANK MILLSTONE - UNIT 3 3/4 10-6 Amendment No. 1Y7.207 0807 J 3 0 2W2

This page intentionally left blank MILLSTONE - UNIT 3 3/4 11-1

• I Amendment Ho.188 0693 i "t4 ; . I

This page intentionally left blank MILLSTONE - UNIT 3 0693 3/4 11-2 AMENDMENT NO. P7b 188

This page intentionally left blank MILLSTONE - UNIT 3 3/4 11-3 Amendment No.188 I Om63

This page intentionally left blank MILLSTONE - UNIT 3 3/4 11-4 AMENDMENT NO. J7, 188 0683 * .A

This page intentionally left blank MILLSTONE - UNIT 3 3/4 11-5 AMENDMENT NO. 7, 188 0093

This page intentionally left blank MILLSTONE 63IT - 3 3/4 11-6, AMENDMENT NO. J7,188 Oe93

BASES FOR SECTIONS 3.0 AND 4.0 LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS

NOTE The BASES contained in succeeding pages summarize the reasons for the Specifications in Sections 3.0 and 4.0, but in accordance with 10 CFR 50.36 are not part of these Technical Specifications.

3/4.0 APPLICABILITY BASES 3/4 LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS 3/4.0 APPLICABILITY Specification 3.0.1 through 3.0.4 establish the general requirements applicable to Limiting Conditions for Operation. These requirements are based on the requirements for Limiting Conditions for Operation stated in the Code of Federal Regulations, 10 CFR 50.36(c)(2): "Limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When a limiting condition for operation of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specification until the condition can be met." SDecification 3.0.1 establishes the Applicability statement within each individual specification as the requirement for when (i.e., in which OPERATIONAL MODES or other specified conditions) conformance to the Limiting Conditions for Operation is required for safe operation of the facility. The ACTION requirements establish those remedial measures that must be taken within specified time limits when the requirements of a Limiting Condition for Operation are not met. There are two basic types of ACTION requirements. The first specifies the remedial measures that permit continued operation of the facility which is not further restricted by the time limits of the ACTION requirements. In this case, conformance to the ACTION requirements provides an acceptable level of safety for unlimited continued operation as long as the ACTION requirements continue to be met. The second type of ACTION requirement specifies a time limit in which conformance to the conditions of the Limiting Condition for Operation must be met. This time limit is the allowable outage time to restore an inoperable system or component to OPERABLE status of for restoring parameters within specified limits. If these actions are not completed within the allowable outage time limits, a shutdown is required to place the facility in a MODE or condition in which the specification no longer applies. It is not intended that the shutdown ACTION requirements be used as an operational convenience which permits (routine) voluntary removal of a system(s) or component(s) from service in lieu of other alternatives that would not result in redundant systems or components being inoperable. The specified time limits of the ACTION requirements are applicable from the point in time it is identified that a Limiting Condition for Operation is not met. The time limits of the ACTION requirements are also applicable when a system or component is removed from service for surveillance testing or investigation of operational problems. Individual specifications may include a specified time limit for the completion of a Surveillance Requirement when equipment is removed from service. In this case, the allowable outage time limits of the ACTION requirements are applicable when this limit expires if the surveillance has not been completed. When a shutdown is required to MILLSTONE - UNIT 3 B 3/4 0-1 AMENDMENT NO. 57 CCT,2 5 it0

3/4.0 APPLICABILITY BASES comply with ACTION requirements, the plant may have entered a MODE in which a new specification becomes applicable. In this case, the time limits of the ACTION requirements would apply from the point in time that the new specification becomes applicable if the requirements of the Limiting Condition for Operation are not met. Specification 3.0.2 establishes that noncompliance with a specification exists when the requirements of the Limiting Condition for Operation are not met and the associated ACTION requirements have not been implemented within the specified time interval. The purpose of this specification is to clarify that (1) implementation of the ACTION requirements within the specified time interval constitutes compliance with a specification and (2)completion of the remedial measures of the ACTION requirements is not required when compliance with a Limiting Condition of Operation is restored within the time interval specified in the associated ACTION requirements. Specification 3.0.3 establishes the shutdown ACTION requirements that must be implemented when a Limiting Condition for Operation is not met and the condition is not specifically addressed by the associated ACTION requirements. The purpose of this specification is to delineate the time limits for placing the unit in a safe shutdown MODE when plant operation cannot be maintained within the limits for safe operation defined by the Limiting Conditions for Operation and its ACTION requirements. It is not intended to be used as an operational convenience which permits (routine) voluntary removal of redundant systems or components from service in lieu of other alternatives that would not result in redundant systems or components being inoperable. This time permits the operator to coordinate the reduction in electrical generation with the load dispatcher to ensure the stability and availability of the electrical grid. The time limits specified to reach lower MODES of operation permit the shutdown to proceed in a controlled and orderly manner that is well within the specified maximum cooldown rate and within the cooldown capabilities of the facility assuming only the minimum required equipment is OPERABLE. This reduces thermal stresses on components of the primary coolant system and the potential for a plant upset that could challenge safety systems under conditions for which this specification applies. If remedial measures permitting limited continued operation of the facility under the provisions of the ACTION requirements are completed, the shutdown may be terminated. The time limits of the ACTION requirements are applicable from the point in time it is identified that a Limiting Condition for Operation is not met. Therefore, the shutdown may be terminated if the ACTION requirements have been met or the time limits of the ACTION requirements have not expired, thus providing an allowance for the completion of the required actions. The time limits of Specification 3.0.3 allow 37 hours1.542 days <br />0.22 weeks <br />0.0507 months <br /> for the plant to be in COLD SHUTDOWN MODE when a shutdown is required during the POWER MODE of operation. If the plant is in a lower MODE of operation when a shutdown is required, the time limit for reaching the next lower MODE of operation applies. However, if a lower MODE of operation is reached in less time than allowed, the total allowable time to reach COLD SHUTDOWN, or other applicable MILLSTONE - UNIT 3 B 3/4 0-2 AMENDMENT NO. 57 On7 e 5 A

3I4.o APPLICABILITY BASES MODE, is not reduced. For example, if HOT STANDBY is reached in 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br />, the time allowed to reach HOT SHUTDOWN is the next 11 hours0.458 days <br />0.0655 weeks <br />0.0151 months <br /> because the total time to reach HOT SHUTDOWN is not reduced from the allowable limit of 13 hours0.542 days <br />0.0774 weeks <br />0.0178 months <br />. Therefore, if remedial measures are completed that would permit a return to POWER operation, a penalty is not incurred by having to reach a lower MODE of operation in less than the total time allowed. The same principle applies with regard to the allowable outage time limits of the ACTION requirements, if compliance with the ACTION requirements for one specification results in entry into a MODE or condition of operation for another specification in which the requirements of the Limiting Condition for Operation are not met. If the new specification becomes applicable in less time than specified, the difference may be added to the allowable outage time limits of the second specification. However, the allowable outage time limits of ACTION requirements for a higher MODE of operation may not be used to extend the allowable outage time that is applicable when a Limiting Condition for Operation is not met in a lower MODE of operation. The shutdown requirements of Specification 3.0.3 do not apply in MODES 5 and 6, because the.ACTION requirements of individual specifications define the remedial measures to be taken. Specification 3.0.4 establishes limitations on MODE changes when a Limiting Condition for Operation is not met.- It precludes placing the facility in a high MODE of operation when the requirements for a Limiting Condition for Operation are not met and continued noncompliance to these conditions would result in a shutdown to comply with the ACTION requirements if a change in MODES were permitted. The purpose of this specification is to ensure that facility operation is not initiated or that higher MODES of operation are not entered when corrective action is being taken to obtain compliance with a specification by restoring equipment to OPERABLE status or parameters to specified limits. Compliance with ACTION requirements that permit continued operation of the facility for an unlimited period of time provides an acceptable level of safety for-continued operation without regard to the status of the plant before or after a MODE change. Therefore, in this case, entry into an OPERATIONAL MODE or other specified condition may be made in accordance with the provisions of the ACTION requirements. The provisions of this specification should not; however, be interpreted as endorsing the failure to exercise good practice in restoring systems or components to OPERABLE status before plant startup. When a shutdown is required to comply with ACTION requirements, the provision of Specification 3.0.4 do not apply because they would delay placing the facility in a lower MODE of operation. Specification 3.0.5 establishes the allowance for restoring equipment to service under administrative controls when it has been removed from service or declared inoperable to comply with ACTIONS. The sole purpose of this Specification is to provide an exception to Specifications 3.0.1 and 3.0.2 (e.g., to not comply with the applicable Required Action(s)) to allow the performance of required testing to demonstrate either:

a. The OPERABILITY of the equipment being returned to service; or

b. The OPERABILITY of other equipment.

MILLSTONE - UNIT 3 B 3/4 0-3 Amendment No. 07, 179 0680

-, T rtd { <sh AL I BASES The administrative controls ensure the time the equipment is returned to service in conflict with the requirements of the ACTIONS is limited to the time absolutely necessary to perform the required testing to demonstrate OPERABILITY. This Specification does not provide time to perform any other preventive or corrective maintenance. An example of demonstrating the OPERABILITY of the equipment being returned to service is reopening a containment isolation valve that has been closed to comply with Required Actions and must be reopened to perform the required testing. An example of demonstrating the OPERABILITY of other equipment is taking an inoperable channel or trip system out of the tripped condition to prevent the trip function from occurring during the performance of required testing on another channel in the other trip system. A similar example of demonstrating the OPERABILITY of other equipment is taking an inoperable channel or trip system out of the tripped condition to permit the logic to function and indicate the appropriate response during the performance of required testing on another channel in the same trip system. Specifications 4.0.1 through 4.0.5 establish the general requirements applicable to Surveillance Requirements. These requirements are based on the Surveillance Requirements stated in the Code of Federal Regulations, 10 CFR 50.36(c)(3): MILLSTONE UNIT 3 B 3/4 O-3a Amendment No. 7, 179

                                                                                ) -I- -; ,.' .

0680

3/4.0 APPLICABILITY BASES "Surveillance requirements are requirements relating to test, calibration, or inspection to ensure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions of operation will be met." Specification 4.0.1 establishes the requirement that surveillances must be met during the OPERATIONAL MODES or other conditions for which the requirements of the Limiting Conditions for Operation apply unless otherwise stated in an individual Surveillance Requirement. The purpose of this specification is to ensure that surveillances are performed to verify the OPERABILITY of systems and components and that parameters are within specified limits to ensure safe operation of the facility when the plant is in a MODE or other specified condition for which the associated Limiting Conditions for Operation are applicable. Failure to meet a Surveillance within the specified surveillance interval, in accordance with Specification 4.0.2, constitutes a failure to meet a Limiting Condition for Operation. Systems and components are assumed to be OPERABLE when the associated Surveillance Requirements have been met. Nothing in this Specification, however, is to be construed as implying that systems or components are OPERABLE when either:

a. The systems or components are known to be inoperable, although still meeting the Surveillance Requirements or

b. The requirements of the Surveillance(s) are known to be not met between required Surveillance performances.

Surveillance requirements do not have to be performed when the facility is in an OPERATIONAL MODE or other specified conditions for which the requirements of the associated Limiting Condition for Operation do not apply unless otherwise specified. The Surveillance Requirements associated with a Special Test Exception are only applicable when the Special Test Exception is used as an allowable exception to the requirements of a specification. Unplanned events may satisfy the requirements (including applicable acceptance criteria) for a given Surveillance Requirement. In this case, the unplanned event may be credited as fulfilling the performance of the Surveillance Requirement. This allowance includes those Surveillance Requirement(s) whose performance is normally precluded in a given MODE or other specified condition. Surveillance Requirements, including Surveillances invoked by ACTION requirements, do not have to be performed on inoperable equipment because the ACTIONS define the remedial measures that apply. Surveillances have to be met and performed in accordance with Specification 4.0.2, prior to returning equipment to OPERABLE status. Upon completion of maintenance, appropriate post maintenance testing is required to declare equipment OPERABLE. This includes ensuring applicable Surveillances are not failed and their most recent performance is in accordance with Specification 4.0.2. Post maintenance testing may not be possible in the current MODE or other specified conditions in the Applicability due to the necessary unit parameters not having been established. In these situations, the equipment may be considered OPERABLE provided testing has been satisfactorily completed to the extent possible and the equipment is not otherwise believed to be incapable of performing its function. This will allow operation to proceed to a MODE or other specified condition where other necessary post maintenance tests can be completed. MILLSTONE - UNIT 3 B 3/4 0-4 Amendment No. P7, J77,213 0913 NOV s mm

• LBDCR No. 04-MP3-015 February 24,2005 314.0 APPLICABILiTY BASES Some examples of this process arc:

a. Auiliaiy feedwater (AFW) pump turbine maintenance during refueling that rers testing at steam pressure > 800 psi. However, if other appropriate testing is satisfictorily completed, the AFW System can be considered OPERABLE. This allows startup and other necessary testing to proceed until the plant reaches the steam pressure required to perform the testing.

b. High pressure safety injection (HPSI) maintenance during shutdown that requires system finctional tests at a specified pressure. Provided other appropriate testing is sa completed, startup an proceed with HPSI considered OPERABLE.

hs allows operation to reach the specified pressure to complete te necessary post maintenance testing.

   &ficationA4.0.2 This specification establishes the limit for which the specified time interval for surveillance requirements may be extended. It permits an allowable extension of the normal surveillance interval to facilitate surveillance scheduling and consideration of plant operating conditions that may not be suitablefor conducting the surveillance; e.g., transient conditions or other ongoing surveillance or maintenance activities. It also provides flexibility to accommodate the length of a fuel cycle for surveillances that are performed at each refueling outage and are specified typically with an 18-month surveIllance interval. It is not intended that this provision be used repeatedly as a convenience to eend surveillance intervals beyond that specified for sueillances that are not performed duing refueling outage. The limitation of 4.0.2 is based an engineering judgment and the recognition that the most probable result of any particular surveillance being performed is the verification of conformance with the surveillance requirements. This provision is sufficient to ensure that the reliability ensured through surveillance activities Is not significantly degraded beyond that obtained from the specified sueillance interval.

Specification 4.0.3 establishes the flexbility to defer declaing affected equipment inoperable or an affected variable outside the specified limits when a Surveillance has not been completed within the specified surveillance interval. A delay period ofup to 24 hous orup to the limit ofthe specified surveillance interval, whichever Is greater, applies from the point in time that it is discovered that the Surveillance has not been performed in accordance with Specification 4.02, and not at the time that the specified surveillance Interval was not met. This delay period provides adequate time to complete Surveillances that have been missed. This delay period permits the completion of a Surveillance before complying with ACTION requirements or other remedial measures that might preclude completion of the Surveillance. The basis for this delay period includes consideration ofunit conditions, adequate planning, availability ofpersonmel, the tie required to perform the Surveillance, the safety significance of the delay in completing the required Surveillance, and the recontion that the most probable result of any paricular Surveillance being performed is the verification of conformance with the requirements. MILLSTONE -UNIT3 B 3/4 0-5 AmendmentNo.,M, 206,244,

                                                           £&          ehavc         L6     2-c-25-96bS

LBDCR No. 04-MP3-015 February 24, 2005 314.0 APPLiCABliTY BASES When a Surveillance with a surveillance interval based not on time intervals, but upon specified unit conditims, operating situations, or requirements of regulations, (eg., prior to entering MODE I after each fuel loading, or in accordance with 10 CFR 50, Appendix J, as modified by approved exemptions, etc.) is discovered to not have been performed when specified, Specification 4.0.3 allows for the full deliy period of up to the specified surveillance interval to perform the Surveillance. Howevr dsince there is not a time interval specified, the missed Srveilance ould be peformed at the first reasonable opportunity. Specification 4.0.3 provides a time limit for, and allowances for the performance oft Surveillances that become applicable as a consequence of MODE changes imposed by ACTION requirements. Failure to comply with specified surveillance intervals for the Surveillance Requirements is expected to be an infirquent occurrence. Use of the delay period established by Specification 4.0.3 is a flexibility which isnot intended to be used as an operational convenience to extend Surveillance intervals. While up to 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> or the limit of the specified surveillance interval is provided to perform the missed Surveillance, it is expected that the missed Surveillance will be performed at the first reasonable opportunity. The detenmination of the first reasonable opportnity hould include consideration of the 1mpact on plant risk (fiom delaying the Sueince as wel as any plant configuration changes required or shutting the plant dcwn to perform the Sunreillance) and impact on any analysis assumptions, in addition to unit conditions, plaing, avaiability ofpersonnel, and the time required to perform the Surveillance. This risk mpact should be managed through the program in place to implement 0 CFR 50.65(a)(4) and its Implementation guidance, NRC Regulatory Guide 1.182, 'Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants." This Regulatory Guide addresses consideration of temporary and aggregate risk Impacts, detemiation of risk management action thresholds, and risk management action up to and including plant shutdown. The missed Surveillance should be treated as an emergent condition as discussed in the Regulatory Guide. The risk evaluation may use quantitative, qualitative, or blended methods. The degree of depth and rigor of the evaluation should be commensuratewith theimprarsce ofthe component. Missed Surveillances for important components shoul be analyzed quntitativey. If lhe results of the risk evaluation determine the risk increase Is significant, this evaluation should be used to determine the safest course of action. All missed Survefllances will be placed in the licensee's Corrective Action Program. Ifa Surveillance is not completed within the allowed delay period, then the equipment is

• considered inoperable or the variable is considered outside the specified limits and the entry into the ACIION requirements for the applicable Limting Condition for Oeeration begins immediately upon expiration ofthe delay period. If a Surveillance is failed within the delay jeriod, then the equipment Is inoperable, or the variable is outside the specified limits and entry nto the ACTION requirements for the applicable Limiing Conditions for Operation begins immediately upon the filum of the Surveillance.

Completion ofthe Surveillance within the delay period allowed by this Specification, or within the Allowed Outage Time of the applicable ACTIONS, restores compliance with Specification 4.0.1. MILLSTONE - UNIT 3 B 314 0-5a AmendmentNo. M. I4f&2QO C#WiA~9 66 i-cQJ 6gbS RASES Specification 4.0.4 establishes the requirement that all applicable surveillances must be met before entry into an OPERATIONAL MODE or other condition of operation specified in the Applicability statement. The purpose of this specification is to ensure that system and component OPERABILITY requirements or parameter limits are met before entry into a MODE or condition for which these systems and components ensure safe operation of the facility. This provision applies to changes in OPERATIONAL MODES or other specified conditions associated with plant shutdown as well as startup. Under the provisions of this specification, the applicable Surveillance Requirements must be performed within the specified surveillance interval to ensure that the Limiting Conditions for Operation are met during initial plant startup or following a plant outage. When a shutdown is required to comply with ACTION requirements, the provisions of Specification 4.0.4 do not apply because this would delay placing the facility in a lower MODE of operation. Specification 4.0.5 establishes the requirement that inservice inspection of ASME Code Class 1, 2, and 3 components and inservice testing of ASME Code Class 1, 2, and 3 pumps and valves shall be performed in accordance with a periodically updated version of Section XI of the ASME Boiler and Pressure Vessel Code and Addenda as required by 10CFR50.55a. These requirements apply except when relief has been provided in writing by the Commission. This specification includes a clarification of the frequencies for performing the inservice inspection and testing activities required by Section XI of the ASME Boiler and Pressure Vessel Code and applicable Addenda. This clarification is provided to ensure consistency in surveillance intervals throughout the Technical Specifications and to remove any ambiguities relative to the frequencies for performing the required inservice inspection and testing activities. Under the terms of this specification, the more restrictive requirements of the Technical Specifications take precedence over the ASME Boiler and Pressure Vessel Code and applicable Addenda. The requirements of Specification 4.0.4 to perform surveillance activities before entry into an OPERATIONAL MODE or other specified condition takes precedence over the ASME Boiler and Pressure Vessel Code provision which allows pumps and valves to be tested up to one week after return to normal operation. The Technical Specification definition of OPERABLE does not allow a grace period before a component, that is not capable of performing its specified function, is declared inoperable and takes precedence over the ASME Boiler and Pressure Vessel Code provision which allows a valve to be incapable of performing its specified function for up to 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> before being declared inoperable. MILLSTONE - UNIT 3 B 3/4 0-6 Amendment No. F7,213 0913 NOV Ie5

L1DCOR 04-MP3002 March25s 2004 3/4.1 RR&CMlMll CONTROLYTg BASES 314.1.1 BOPLATION CON RQL 314.1.1.1 and 314.1.1.2 SHUTDOWN MARGN A sufficient SH OWN MARGIN enswes that: (1) the reactor can be made sulcritica from a11 operating conditions, (2)the reactivity transients associated withpostulated accident condtons are contollable wit accepable lmits, and (3)the reactor will be maintained ufficiently auberitical to preclude Inadvertent criticality In the shutdown conditionL SLUTDOWN MARGIN requirements vary throughout core life as a fimcion of fuel depletion, RCS boron cocentration, and RCO T,,, In MODES 1 and 2, the most resictve condition occurs atEOLwith T1 , atno load operating emperatur, andis associated with a postlated steamlinebreak accidentandresultig uncontrolled RCS cooldown. Inthe anaysis of this acciden, a minlmum SHUTDOWN MARGIN as defined in Specification 3J4.1.1.1.1 is required to control tef reactivity transient Accordin, the SHDOWN MARGN enquirment is based upon fi limiting condition and is cosistent with FSAR safety analysis assumptions. In MODES 3, 4 and 5, the most restrictive condition occurs at BOL associated with a boron diluflonccident. In the analysis ofths accident, a minimum SHUTDOWN MARGIN as defined In Specification 314.1.1.1.2 is requied to allow the operator 15 mhtes from the initiation of the Shutdown Margin Monitor alarm to total losS Of SHUTDOWN MARG3IN. Accordingly, the SHUrDOWN MAR N requirement Isbased upon this limiting requirenent and is consistent with the accident analysis assumption. The locldng closed ofithe required valves InMODE S (with the loops not filled) will preclude the possibility of uncontrolled boroa diution ofthe Reactor Coolant System by preventing flow of unborated water to the ROB. The limitations an moderator temperature coefficient (MTQ are provided to ensure that thefvalue of this coefficient remains within the limiting condition assumed in the PSAR accident and transient anayses. The MTC values of this specification ae applicable to a specific set of plant conditions; accordingly, verification of MTC values at conditions other than those explicifly stated will require extrapolation to those conditions in order to permit an accurate comparison. The most negative MTC, value equivalent to the most positive moderator density coefficient (MDC), was obtained by Incrementally correcting the MDC used in the FSAR analyses to nominal operaig conditions. MITISTONE-UNIT3 B 3/4 1-1 AmendmentNo9.694,99,W,

                                                        ,a2k3C21GLv7QD-              &t   % -c5-&6CbS

REACTIVITY CONTROL SYSTEMS BASES MODERATOR TEMPERATURE COEFFICIENT (Continued) These corrections involved: (1) a conversion of the MDC used in the FSAR safety analyses to its equivalent MTC, based on the rate of change of moderator density with temperature at RATED THERMAL POWER conditions, and (2) subtracting from this value the largest differences in MTC observed between EOL, all rods withdrawn, RATED THERMAL POWER conditions, and those most adverse conditions of moderator temperature and pressure, rod insertion, axial power skewing, and xenon concentration that can occur in normal operation and lead to a significantly more negative EOL MTC at RATED THERMAL POWER. These corrections transformed the MDC value used in the FSAR safety analyses into the limiting End of Cycle Life (EOL) MTC value. The 300 ppm surveillance limit MTC value represents a conservative MTC value at a core condition of 300 ppm equilibrium boron concentration, and is obtained by making corrections for burnup and soluble boron to the limiting EOL MTC value. The Surveillance Requirements for measurement of the MTC at the beginning and near the end of the fuel cycle are adequate to confirm that the MTC remains within its limits since this coefficient changes slowly due principally to the reduction in RCS boron concentration associated with fuel burnup. 3Z4.1.1.4 MINIMUM TEMPERATURE FOR CRITICALITY This specification ensures that the reactor will not be made critical with the Reactor Coolant System average temperature less than 551. This limitation is required to ensure: (1) the moderator temperature coefficient is within it analyzed temperature range, (2) the trip instrumentation is within its normal operating range, (3) the P-12 interlock is above its setpoint, (4) the pressurizer is capable of being in an OPERABLE status with a steam bubble, and (5) the reactor vessel is above its minimum RTNDT temperature. 3/4.1.2 DELETED MILLSTONE - UNIT 3 B 3/4 1-2 Amendment No. 7y, Fp, 7IF7197 0779

REACTIVITY CONTROL SYSTEMS BASES 3/4.1.3 MOVABLE CONTROL ASSEMBLIES I The specifications of this section ensure that: (1) acceptable power distribution limits are maintained, (2) the minimum SHUTDOWN MARGIN is maintained, and (3) the potential effects of rod misalignment on associated accident analyses are limited. OPERABILITY of the control rod position indicators is required to determine control rod positions and thereby ensure compliance with the control MILLSTONE - UNIT 3 B 3/4 1-3 Amendment No. fl, pp, pl, 11i, 0779 F7, 1fM, 197

ALMs. IR V I I I un uKUL a - 11l Cz .* 3-1 U-U LBDCR 3-9-02 August 27. 2002 September 4. 2002 BASES MOVABLE CONTROL ASSEMBLIES (Continued) rod alignment and insertion limits. Verification that the Digital Rod Position Indicator agrees with the demanded position within +12 steps at 24, 48, 120, and fully withdrawn position for the Control Banks and 18, 210, and fully withdrawn position for the Shutdown Banks provides assururances that the Digital Rod Position Indicator is operating correctly over the full range of indication. Since the Digital Rod Position Indication System does not indicate the actual shutdown rod position between 18 steps and 210 steps, only points in the indicated ranges are picked for verification of agreement with demanded position. The ACTION statements which permit limited variations from the basic requirements are accompanied by additional restrictions which ensure that the original design criteria are met. Misalignment of a rod requires measurement of peaking factors and a restriction in THERMAL POWER. These restrictions provide assurance of fuel rod integrity during continued operation. In addition, those safety analyses affected by a misaligned rod are reevaluated to confirm that the results remain valid during future operation. The maximum rod drop time restriction is consistent with the assumed rod drop time used in the safety analyses. Measurement with Ta.g greater than or equal to 551'F and with all reactor coolant pumps operating ensures that the measured drop times will be representative of insertion times experienced during a Reactor trip at operating conditions. The required rod drop time of < 2.7 seconds specified in Technical Specification 3.1.3.4 is used in the FSAR accident analysis. A rod drop time was calculated to validate the Technical Specification limit. This calculation accounted for all uncertainties, including a plant specific seismic allowance of 0.51 seconds. Since the seismic allowance should be removed when verifying the actual rod drop time, the acceptance criteria for surveillance testing is 2.19 seconds (References 4 and 5). Control rod positions and OPERABILITY of the rod position indicators are required to be verified on a nominal basis of once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> with more fre-quent verifications required if an automatic monitoring channel is inoperable. These verification frequencies are adequate for assuring that the applicable LCOs are satisfied. The Digital Rod Position Indication (DRPI) System is defined as follows:

• Rod position indication as displayed on DRPI display panel (MB4), or
• Rod position indication as displayed by the Plant Process Computer System With the above definition, LCO, 3.1.3.2, 'ACTION a." is not applicable with either DRPI display panel or the plant process computer points OPERABLE.

The plant process computer may be utilized to satisfy DRPI System requirements which meets LCO 3.1.3.2, in requiring diversity for determining digital rod position indication. Technical Specification SR 4.1.3.2.1 determines each digital rod position indicator to be OPERABLE by verifying the Demand Position Indication System and the DRPI System agree within 12 steps at least once each 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />, except during the time when the rod position deviation monitor is inoperable, MILLSTONE - UNIT 3 B 3/4 1-4 Amendment No. fq, 0950 Revised by NRC letter dated 02/26/2004.

REACTIVITY CONTROL SYSTEMS LBDCR 3-10-02 August 27, 2002 BASES MOVABLE CONTROL ASSEMBLIES (Continued) then compare the Demand Position Indication System and the DRPI System at least once each 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />. The Rod Deviation Monitor is generated only from the DRPI panel at MB4. Therefore, when rod position indication as displayed by the plant process computer is the only available indication, then perform SURVEILLANCE REQUIREMENTS every 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />. Technical Specification SR 4.1.3.2.1 determines each digital rod position indicator to be OPERABLE by verifying the Demand Position Indication System and the DRPI System agree within 12 steps at least once each 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />, except during the time when the rod position deviation monitor is inoperable, then compare the Demand Position Indication System and the DRPI System at least once each 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />. The Rod Deviation Monitor is generated only from the DRPI panel at MB4. Therefore, when rod position indication as displayed by the plant process computer is the only available indication, then perform SURVEILLANCE REQUIREMENTS every 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />. Additional surveillance is required to ensure the plant process computer indications are in agreement with those displayed on the DRPI. This additional SURVEILLANCE REQUIREMENT is as follows: Each rod position indication as displayed by the plant process computer shall be determined to be OPERABLE by verifying the rod position indication as displayed on the DRPI display panel agrees with the rod position indication as displayed by the plant process computer at least once per 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />. The rod position indication, as displayed by DRPI display panel (MB4), is a non-QA system, calibrated on a refueling interval, and used to implement T/S 3.1.3.2. Because the plant process computer receives field data from the same source as the DRPI System (MB4), and is also calibrated on a refueling interval, it fully meets all requirements specified in T/S 3.1.3.2 for rod position. Additionally, the plant process computer provides the same type and level of accuracy as the DRPI System (MB4). The plant process computer does not provide any alarm or rod position deviation monitoring as does DRPI display panel (MB4). For Specification 3.1.3.1 ACTIONS b. and c., it is incumbent upon the plant to verify the trippability of the inoperable control rod(s). Trippability is defined in Attachment C to a letter dated December 21, 1984, from E. P. Rahe (Westinghouse) to C. 0. Thomas (NRC). This may be by verification of a control system failure, usually electrical in nature, or that the failure is associated with the control rod stepping mechanism. In the event the plant is unable to verify the rod(s) trippability, it must be assumed to be untrippable and thus falls under the requirements of ACTION a. Assuming a controlled shutdown from 100% RATED THERMAL POWER, this allows approximately 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> for this verification. For LCO 3.1.3.6 the control rods shall be limited in insertion as defined in the Core Operating Limits Report (COLR). The BASES for the Rod Insertion Limit (RIL) is located in the COLR (Reference 3.) and the current cycle reload 50.59 evaluation. MILLSTONE - UNIT 3 B 3/4 1-5 Amendment No. f, 0950 Is , inte U .. I . . A, _ I_ . A

LBDGR No. 04-MP3-01 5 February 24, 2005 REACIIVT CONlROL SYS EMS BASES MOVABLE CONTROL ASSMBLTES Continued For Specification 3.1.3.1 ACTIONS b. and c, it is incumbent upon tIe plant to verify the trippability of the inoperable control rod(s). Trippability Is defined In Attachment C to a letter dated December 21, 1984, fiom E P. Rahe (Westinhouse) to C. 0. Thomas (RC). This may be by verification ofa control system failure, usually electrical in nature, or that the failure is associated with the control rod stepping mechanism. In the event the plant is unable to verify the rod(s) trippability, it must be assumed to be untrippable and thus fills under the requirements of ACTION a. Assuming a controlled shutdown fium 100% RATED THERMAL POWER, this allows approximately 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> for this verification. For LCO 3.1.3.6 the control bank insertion limits are specified In the CORE OPERAMhNG LIiTS REPORT (COLR). These insertion limits are the initial assumptions in safety analyses that assume rod insertion upon reactor trip. The insertion limits directly affect core power and fuel burnup distributions, assumptions of available SHEFFDOWN MARGIN, and initial reactivity insertion rate. The applicable I&C calibration procedure (Reference 1.) being current indicates the associated circuitry is OPERABLE. The arct conditions when the Lo-Lo and Lo alarms of the RIL Monitor are limited below the RIL specified in the COLR. The RIL Monitor remains OPERABLE because the lead control rod bank still has the Lo and Lo-Lo alarms greater than or equal to the RIL When rods are at the top ofthe core, the Lo-Lo alarm is limited below the RIL to prevent spurious alarms. The RIL is equal to the Lo-Lo alarm until the adjustable upper limit setpoint on the RIL Monitor is reached, then the alarm remains at the adjustable upper limit setpoint. When the RIL is in the region above the adjustable upper limit setpoint, the Lo-Lo alarm is below the RIL

References:

1. IC 3469N08, Rod Control Speed, Lasertion l~tm and Control TAVE AuctioneeredlDeviation Alarms.

2. LetterNS-OPLS-OPL-1-91-226, (WestinghouseLetter NEU-91-563), dated Apnl 24,1991.

3. Millstone Unit 3 Technical Requirements Manual, Appendix 8.1, "CORE OPERATING LIMT REPORr. I

4. Westinghouse Letter NEU-97-298, 'Millstone Unit 3 - RCCA Drop Ttmeu,dated November 13, 1997.

5. Westinghouse Letter 9BNEU-G-0060, O'Millstone Unit 3 - Robust Fuel Assembly (Design Report) and Generic SECL m dated October 2, 1998.

MILLSTONE-UN1T3 B 314 1-6 AmendmentNo.

LBDCR No. 04-MP3-015 February 24,2005 3142 POWER DISTRIBUFJON LIMITS BASES The specifications of this section provide assunce of fuel integrity during Condition I (Normal Operation) and II (Incidents of Moderate Frequency) events by: (1) maintaining the mzinirmm DNBR in the core greater than or equal to the design limit during normal operation and in short-term transients, and (2) limiting the fission gas release, fuel pellet temperature, and cladding mechanical properties to within assumed design Criteria. In addition, limiting the peak linear power density during Condition I events provides assurance that the initial conditions assumed for the LOCA analyses are met and the ECCS acceptance criteria limit of 2200°F is not exceeded. The definitions of certain hot channel and pealdng factors as used in these specifications are as follows: FQ(Z) Heat Flux Hot Channel Factor, is defined as the maximum local heat flux on the surface of a fuel rod at core elevation Z divided by the average fiel rod heat flux, allowing for manuficturing tolerances on fuel pellets and rods; and FN Nuclear Enthalpy Rise Hot Channel Factor, is defined as the ratio of the integral of linear power along the rod with the highest integrated power to the average rod power. 3142.1 AXIAL FLUX DIFFIMENCE The limits on AXIAL FLUX DIFFERENCE (APD) assure that the FQ(Z) upper bound envelope of the FQ limit specified in the CORE OPERATING LIMITS REPORT3 (COLR) times the normalized axial pealdng fiactor is not exceeded during either normal operation or in the event of xenon redistribution following power changes. Target flux difference is determined at equilibrium xenon conditions. The full-length rods may be positioned within the core in accordance with their respective insertion limits and should be inserted near their normal position for steadystate operation at high power levels. The value of the target flux difference obtained under thesm conditions divided by the fraction of RATED THERMAL POWER is the target flux difference at RATED THERMAL POWER for the associated core burnup conditions. Target flux differences for other THERMAL POWER levels are obtained by multiplying the RAIED THERMAL POWER value by the appropriate fractional THERMAL POWER level. The periodic updating ofthe target flux difference value is necessary to reflect core brnup considerations. MILLSTONE - UNIT 3 B 314 2-1 Amendment No. 60, 60,

                                                                ,2{w~ C~a.j             t     -9/g

• LBDCR No. 04-MP3-015 February 24,2005 POWER DISTRIBUTION LIMITS BASES AXIALE DlFFEREENCE (Continued)

At power levels below APLOD, the limits on APD are defined in the COLR consistent with the Relaxed Axial Offset Control (RAOC) operating procedure and limits. These limits were calculated in a manner such that expected operational transients, e.g., load follow operations, would not result in the AFD deviating outside of those limits. However, in the event such a deviation occurs, the short period of time allowed outside of the limits at reduced power levels will not result in significant xenon redistribution such that the envelope of peakdng factors would change sufficiently to prevent operation in the vicinity of the APLN power level. Atpower levcls greater than APIND, two modes ofopeation are permissible: (1) RAOC, the AFD limit of which are defined in the COLR, and (2) base load operation, which is defined as the maintenance of the AFD within COLR specifications band about a target value. The RAOC operating procedure above APLND is the same as that defined for operation below APLN. However, it is possible when following extended load following maneuvers that the AFD limits may result in restrictions in the maximum allowed power or AFD in order to guaantee operation -withFQ(Z) less than its limiting value. To alow operation at the maximum permissible power level, the base load operating procedure restricts the indicated APD to relatively small target band (as specified in the COLR) and power swings (APLND: power s APLBL or 100% RATED THERMAL POWER, whichever Is lower). For base load operation, it is expected that the plant will operate within the target band. Operation outside of the target band for the short time period allowed will not result in significant xenon redistribution such that the envelope of peaking factors would change sufficiently to prohibit continued operation in the power region defined above. To assure there is no residual xenon redistribution impact from past operation on the base load operation, a 24-hour waiting period at a power level above APLM and allowed by RAOC is necessary. During this time period load changes and rod motion are resticted to that allowed by the base load procedure. After the waiting period, extended base load operation is permissible. The computer determines the I-minute average of each of the OPERABLE excore detector outputs and provides an alasm message Immediately if the AFD for at least 2 of 4 or 2 of 3 OPERABLE excore channels are: (1) outside the allowed delta-I power opeating space (for RAOC operation), or (2) outside the allowed delta-I target band (for base load operation). These alarms are active when power is greater than (1) S0% of RATED THERMAL POWER (for RAOC operation), or MILLSTONE - UNIT 3 B 3/4 2-2 Amendment No. 69, 6G,

POWER DISTRIBUTION LIMITS IRA!CFS AXIAL FLUX DIFFERENCE (Continued) (2) APLND (for base load operation). Penalty deviation minutes for base load operation are not accumulated based on the short period of time during which operation outside of the target band is allowed. 3/4.2.2 and 3/4.2.3 HEAT FLUX HOT CHANNEL FACTOR and RCS FLOW RATE AND NUCLEAR ENTHALPY RISE HOT CHANNEL FACTOR The limits on heat flux hot channel factor, RCS flow rate, and nuclear enthalpy rise hot channel factor ensure that: (1) the design limits on peak local power density and minimum DNBR are not exceeded and (2) in the event of a LOCA the peak fuel clad temperature will not exceed the 2200'F ECCS acceptance criteria limit. Each of these is measurable but will normally only be determined periodically as specified in Specifications 4.2.2 and 4.2.3. This periodic surveillance is sufficient to ensure that the limits are maintained provided:

a. Control rods in a single group move together with no individual rod insertion differing by more than +12 steps, indicated, from the group demand position;

b. Control rod groups are sequenced with overlapping groups as described in Specification 3.1.3.6;

c. The control rod insertion limits of Specifications 3.1.3.5 and 3.1.3.6 are maintained; and

d. The axial power distribution, expressed in terms of AXIAL FLUX DIFFERENCE, is maintained within the limits.

FNAH will be maintained within its limits provided Conditions a. through

d. above are maintained. The relaxation of FN H as a function of THERMAL POWER allows changes in the radial power shape for all permissible rod insertion limits.

The FNAH as calculated in Specification 3.2.3.1 is used in the various accident analyses where FNAH influences parameters other than DNBR, e.g., peak clad temperature, and thus is the maximum "as measured" value allowed. MILLSTONE - UNIT 3 B 3/4- 2-3 Amendment No. F9, F 217 0985

POWER DISTRIBUTION LIMITS 3/4.2.2 and 3/4.2.3 HEAT FLUX HOT CHANNEL FACTOR and RCS FLOW RATE AND NUCLEAR ENTHALPY RISE HOT CHANNEL FACTOR (Continued) Margin is maintained between the safety analysis limit DNBR and the design limit DNBR. This margin is more than sufficient to offset any rod bow penalty and transition core penalty. The remaining margin is available for plant design flexibility. When an F. measurement is taken, an allowance for both experimental error and manufacturing tolerance must be made. An allowance of 5% is appropriate for a full core map taken with the incore detector flux mapping system and a 3% allowance is appropriate for manufacturing tolerance. The heat flux hot channel factor, F,(Z), is measured periodically using the incore detector system. These measurements are generally taken with the core at or near steady state conditions. Using the measured three dimensional power distributions, it is possible to derive FQM(Z), a computed value of F,(Z). However, because this value represents a steady state condition, it does not include the variations in the value of FQ(Z) that are present during nonequilibrium situations. To account for these possible variations, the steady state limit of FQ(Z) is adjusted by an elevation dependent factor appropriate to either RAOC or base load operation, W(Z) or W(Z)8L1 that accounts for the calculated worst case transient conditions. The W(Z) and W(Z)B, factors described above for normal operation are specified in the COLR per Specification 6.9.1.6. Core monitoring and control under nonsteady state conditions are accomplished by operating the core within the limits of the appropriate LCOs, including the limits on AFD, QPTR, and control rod insertion. Evaluation of the steady state F,(Z) limit is performed in Specification 4.2.2.1.2.b and 4.2.2.1.4.b while evaluation nonequilibrium limits are performed in Specification 4.2.2.1.2.c and 4.2.2.1.4.c. When RCS flow rate and FNaH are measured, no additional allowances are necessary prior to comparison with the limits of the Limiting Condition for Operation. Measurement errors of 2.4% for RCS total flow rate and 4% for FNH have been allowed for in determination of the design DNBR value. The measurement error for RCS total flow rate is based upon performing a precision heat balance and using the result to calibrate the RCS flow rate indicators. Potential fouling of the feedwater venturi which might not be detected could bias the result from the precision heat balance in a non-conservative manner. Therefore, a penalty of 0.1% for undetected fouling of the feedwater venturi will be added if venturis are not inspected and cleaned at least once for 18 months. Any fouling which might bias the RCS flow rate measurement greater than 0.1% can be detected by monitoring and trending various plant performance parameters. If detected, action shall be taken before performing subsequent precision heat balance measurements, i.e., either the effect of the fouling shall be quantified and compensated for in the RCS flow rate measurement or the venturi shall be cleaned to eliminate the fouling. MILLSTONE - UNIT 3 B 3/4 2-4 Amendment No. 77, F9, 77%, 217 0985

LBDCR No. 04-MP3-015 February 24, 2005 POWER DTSrRIBUIMON LlMITrS BASES HEAT FLUX HOT CHANNEL FACITOR and RCS ELOW RATE AND NUCLEAR ENTHAL*PY RISE HOT-CHANNEL FACTOR (Continued) The 12-hour periodic surveillance of indicated RCS flow is sufficient to detect only flow degradation which could lead to operation outside the acceptable region of operation defined in Specifications 3.2.3.1. 3/4.2A DRANTPOWER LTRATIO The QUADRANT POWER TILT RATIO limit assures that the radial power distribution satisfies the design values used in the power capability analysis. Radial power distribution measur nts are made during STARTUP testing and periodically during POWER OPERATION. The limit of 1.02, at which corrective action is required, provides DNB and linear heat generation rate protection with x-y plane power tilts. A limiting tilt of 1.025 can be tolerated before the margin for uncertainty in FQ is depleted. A limit of 1.02 was selected to provide an allowance for the uncertainty associated with the indicated power tilt. The 2-hour time allowance for operation with a tilt condition greater than 1.02 but less than 1.09 is provided to allow identification and correction ofa dropped or misaligned control rod. In the event such action does not correct the tilt, the margin for uncertainty on FQ is reinstated by reducing the maximum allowed power by 3% for each percent of tilt in excess of 1. For purposes of monitoring QUADRANT POWERLT RATIO when one excore detector is inoperable, the moveable incore detectors are used to confirm that the normalized symmetric power distribution is consistent with the QUADRANT POWER TILT RATIO. The incore detector monitoring is done with a full incore flux map or two sets offour symmetric thimbles. The two sets of four symmetric thimbles is a unique set of eight detector locations. These locations are C-8, E-5, E-11, H-3. H-13, L-5, L-1, N-S. 3142.5 DNB PARAMEIERS

        'Me lmts on the DNB-related parameters assure that each of the parameters are maintained within the normal steady-state envelope of operation assumed in the transient and accident analyses. The limits are consistent with the initial FSAR assumptions and have been analytically demonstrated adequate to maintain a minimum DNBR greater than the design limit throughout each anayzed transient. The indicatedT. values MILLSTONE - UNIT 3                          B 314 2-5               Amendment No. E, 60, 0 M, 4y j-                        g-     65

LBDCR 04-P34002 March 25, 2004

                              .i POWER DISTRIBUlWON LUMIT BASES DNB PARAMTERS (Continued) and ate indicated pressurizer pressure values ar specified in the CORE OPERATNG IMITS REPORT. The calculated values of the DNB related parameters will be an average of the                 I indicated values for the OPERABLE channels.

The 12-hour periodic surveillance ofthese parameters through instrument readout is sufficient to ensure that the parameters arc restored within their limits following load dhanges and other expected transient operation. Measurement uncertainties have been accounted for In determining the parameter limits. MlLlSTONE - UNIT 3 B 3/4 2-6 Amnendment No. 4, 60, 4*, W e?- 46 4

LBDCRNo. 04-MP3-15 February 24, 2005 314.3 lNSTRUMENTATION BASES 314.3.1 and 3/4.3.2 REACTOR TRIP SYSTEM INSTRUMENTATION and ENGINEERED SAPM-YFEAlllRES ACT UATION UiYSI Nl-MNTT The OPERABILITY of the Reactor Trip System and the Engineered Safety Features Actuation System instrumentation and interlocks ensres that: (1) the associated action and/or Reactor trip will be initiated when the parameter monitored by each channel or combination thereofreaches its sepoint, (2) the specified coincidence logic is maintained, (3) sufficient redundancy is maintained to permit a channel to be out of service for testing or mntenance, and (4) sufficient system functional capability is available from diverse parameters. The OPERABLITY of these systems is required to provide the overall reliability, redundancy, and diversity assumed available In the facility design for the protection and mitigation of accident and transient conditions. The integrated operation of each of these systems is consistent with the assumptions used in the safety analyses. The Surveillance Requirements specified for these systems ensure that the overall system functional capability is maintained comparable to the original design standards. The periodic surveillance tests performed at the minimum frequencies are sufficient to demonstrate this capability. The Engineered Safety Features Actuation System Nominal Trip Setpoints specified in Table 3.34 are the nominal values of which the bistables are set for each functional unit The Allowable Values (Nominal Trip Setpoints

• the calibration tolerance) are considered the Iimiting Safety System Settings as identified in I0CFR5.36 and have been selected to mitigate the consequences of accidents. A Setpoint is considered to be consistent with the nominal value when the measured 'as left" Setpoint is within the administratively controlled (A)calibration tolerance identified in plant procedures (*Whch specifies the difference between the Allowable Value and Nominal Tip Setpoit). Additionally, the Nominal Trip Setpoints may be adjusted in the conservative direction provided the calibration tolerance remains unchanged.

Measurement and Test Equipment accuracy is administratively controlled by plant procedures and is included in the plant uncertainty calculations as defined in WCAP-10991. OPERABIIUTY determinations are based on the use of Me=asureent and Test Equipment that conforms with the accuracy used in the plant uncertainty calculation. The Allowable Value specified in Table 3.3-4 defines the limit beyond which a channel is inoperable. If the process rack bistable setting is measured within the "as left" calibration tolerance, which specifies the difference between the Allowable Value and Nominal Trip Setpoint, then the channel is considered to be OPERABLE. M ISTONE - UIT 3 B 3/4 3-1 Amendment No. , sZ42~Q && (c9 5

LBDCR No. 04-MP3-015 February 24,2005 BASES 3/4.3.1 and 314.3.2 REACTOR TRW SYSTEM INSTRUMENTATION and ENOINEERED SAFEW FEATURES -ACTwUAT70N SYSTEM INSTRUMENTATICON Contillued Ihe methodology, as defined in WCAP-10991 to derive the Nominal Tlp Setpoints, is based upon combining all of the uncertainties in the channels. Inherent in the determination of the Nominal Trip Setpoints are the magnitudes of these channel uncertainties. Sensors and other instrumentation utilized in these channels should be capable of operating within the allowances of these uncertainty magnitudes. Occasional drift in excess of the allowance may be determined to be acceptable based on the other device performance characteristics. Device drift in excess ofthe allowance that is more than occasional, may be indicative ofmore serious problems and would warrant firther investigation. Ihe above Bases does not apply to the Control Building Inlet Ventilation radiation monitors ESF Table (Item 7E). For these radiation monitors the allowable values are essentially nominal values. Due to the uncertainties involved in radiological parameters, the methodologies ofWCAP-10991 were not applied. Actual trip selpoints will be reestablished below the allowable value based on calibration accuracies and good practices. The OPERABILITY requirements for Table 3.3-3, Functional Units 7.a, "Control Building Isolation, Manual Actuation," and 7e, "Control Building Isolation, Control Building Inlet Ventilation Radiation," are defied by table notation "". These fimctional units are required to be OPERABLE at all times during plant operation in MODES 1,2, 3, and 4. These functional units are also required to be OPERABLE during fuel movement within containment or the spent fuel pool, as specified by table notation "". This table notation is also applicable during fuel movement within containment or the spent fuil pool. The fuel handling accident analyses assume that during a fuel handling accident some of the fuel that is dropped and some of the fuel impacted upon is damaged. Therefore, the movement of either new or irradiated fuel (assemblies or individual fuel rods) can cause a fuel handling accident, and functional units 7.a and 7.e are required to be OPERABLE whenever new or irradiated fuel is moved within the,containment or the storage pool. Tble notation "*" of Table 4.3-2 has the same applicability. The verification ofresponse time at the specified frequencies provides assurance that the reactor trip and the engineered safety featusr actuation associated with each channel is completed within the time limit assumed in te safety analysis. No credit is taken in the analysis for those channels with response times indicated as not applicable (i.e., NA.). MILLSTONE - UNIT 3 B 3/4 3-2 Amendment No. 4,4,459, 4-, M,.

                                                                                              & SO pWCa' (J4@*                  et i-5          9u

INSTRUMENTATION BASES 3/4.3.1 and 3/4.3.2 REACTOR TRIP SYSTEM INSTRUMENTATION and ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION (Continued) Response time may be verified by actual response time tests in any series of sequential, overlapping or total channel measurements, or by the summation of allocated sensor, signal processing and actuation logic response times with actual response time tests on the remainder of the channel. Allocations for sensor response times may be obtained from: (1) historical records based on acceptable response time tests (hydraulic, noise, or power interrupt tests), (2) inplace, onsite, or offsite (e.g. vendor) test measurements, or (3) utilizing vendor engineering specifications. WCAP- I3632-P-A, Revision 2, "Elimination of Pressure Sensor Response Time Testing Requirements" provides the basis and methodology for using allocated sensor response times in the overall verification of the channel response time for specific sensors identified in the WCAP. Response time verification for other sensor types must be demonstrated by test. Detector response times may be measured by the in-situ online noise analysis-response time degradation method described in the Westinghouse Topical Report, "The Use of Process Noise Measurements to Determine Response Characteristics of Protection Sensors in U.S. Plants," dated August 1983. WCAP-14036, Revision 1,"Elimination of Periodic Protection Channel Response Time Tests" provides the basis and methodology for using allocated signal processing and actuation logic response times in the overall verification of the protection system channel response time. The allocations for sensor, signal conditioning and actuation logic response times must be verified prior to placing the component in operational service and re-verified following maintenance that may adversely affect response time. In general, electrical repair work does not impact response time provided the parts used for repair are of the same type and value. Specific components identified in the WCAP may be replaced without verification testing. One example where response time could be affected is replacing the sensing assembly of a transmitter. The Engineered Safety Features Actuation System senses selected plant parameters and determines whether or not predetermined limits are being exceeded. If they are, the signals are combined into logic matrices sensitive to combinations indicative of various accidents, events, and transients. Once the required logic combination is completed, the system sends actuation signals to those Engineered Safety Features components whose aggregate function best serves the requirements of the condition. As an example, the following actions may be initiated by the Engineered Safety Features Actuation System to mitigate the consequences of a steam line break or loss-of-coolant accident: (I) Safety Injection pumps start and automatic valves position, (2) Reactor trip, (3) feed-water isolation, (4) startup of the emergency diesel generators, (5) quench spray pumps start and automatic valves position, (6) containment isolation, (7) steam line isolation, (8) Turbine trip, (9) auxiliary feedwater pumps start, (10) service water pumps start and automatic valves position, and (11) Control Room isolates. MILLSTONE - UNIT 3 B 314 3-2a Amendment No. 3, 9-, A9, 219

LBDCR No. 04-MP3-015 February 24, 2005 BASES 3/43.1 and 3/4.3.2 REACT TRIP SYSTEM INSTRUMENTATION and EGINEERED SA:EIFEATURES ACIUATION SYSTEM INSTRUMENTATTON (Continued) For slave relays, or any auxliary relays In ESFAS circuits that are of the type Potter & Brumfield MDR series relays, the SLAVE RELAY TEST is performed at an 'W fiequency (at least once eveiy 18 months) provided the relays meet the reliability assessment criteria presented in WCAP-13878, "Reliability Assessment ofPotter and Brumfield MDR series relays," and WCAP-13900, "Extension of Slave Relay Surveillance Test Intervals." The reliability assessments performed as part ofthe aforementioned WCAPs are relay specific and apply only to Potter and Brumfield MDR series relays. Noie that for normally energized applications the relays may have to be replaced periodically in accordance with the guidance given in WCAP-13878 for MDR relays. REACTOR BRWPEAKER This trip function applies to the reactor (rip breakers (RTBs) exclusive of individual trip mechanisms. The LCO requires two OPERABIE trains of trip breakers. A trip breaker train consists of all trip breakers associated with a single RIS logic train that are racled in, closed, and capable of supplying power to the control rod drive (CRD) system. Thus, the train may consist of the main breaker, bypass breaker, or main breaker and bypass breaker, depending upon the system configurationL TWo OPERABLE trains ensure no single random failure can disable the R1S trip capability. These trip functions must be OPERABLE in MODE I or 2 when the reactor is critical. In MODE 3,4, or 5, these RTS trip functions must be OPERABLE when the RTBs or associated bypass breakers are closed, and the CRD system is capable of rod withdrawaL BYPASSED CHANNEL* - Tecnical Specifications 33.1 and 33.2 often allow the bypassing of instrument Channels in the case of an inoperable instrument or for surveillance testing. A BYPASSED CHANNEL shall be a channel which is:

• Required to be in its accident or tripped condition, but is M presently in its accident or tripped condition using a method described below, or
• Prevented from tripping.

MILLSTONE - UNIT 3 B 3/4 3-2b Amendment No. e49, (2ciif- g 3 -QJ5

INSTRUMENTATION BASES 3/4.3.1 and 3/4.3.2 REACTOR TRIP SYSTEM INSTRUMENTATION and ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION (Continued) A channel may be bypassed by:

• Insertion of a simulated signal to the bistable; or
• Failing the transmitter or input device to the bypassed condition; or
• Returning a channel to service in a untripped condition; or
• An equivalent method, as determined by Engineering and I&C

*Bypass switches exist only for NIS source range, NIS intermediate range, and containment pressure Hi-3.

TRIPPED CHANNEL - Technical Specifications 3.3.1 and 3.3.2 often require the tripping of instrument channels in the case of an inoperable instrument or for surveillance testing. A TRIPPED CHANNEL shall be a channel which is in its required accident or tripped condition. A channel may be placed in trip by:

• The Bistable Trip Switches; or
• Insertion of a simulated signal to the bistable; or
• Failing the transmitter or input device to the tripped condition; or
• An equivalent method, as determined by Engineering and I&C The Engineered Safety Features Actuation System interlocks perform the following functions:

P-4 Reactor tripped - Actuates Turbine trip, closes main feedwater valves on Tavg below Setpoint, prevents the opening of the main feedwater valves which were closed by a Safety Injection or High Steam Generator Water Level signal, allows Safety Injection block so that components can be reset or tripped. Reactor not tripped - prevents manual block of Safety Injection. MILLSTONE - UNIT 3 B 3/4 3-3 Amendment No. 4-3-, 64,219

INSTRUMENTATION BASES 3/4.3.1 and 3/4.3.2 REACTOR TRIP SYSTEM INSTRUMENTATION and ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION (Continued) P- I 1 On increasing pressurizer pressure, P- I l automatically reinstates Safety Injection actuation on low pressurizer pressure and low steam line pressure. On decreasing pressure, P-Il allows the manual block of Safety Injection actuation on low pressurizer pressure and low steam line pressure. P-12 On increasing reactor coolant loop temperature, P-12 automatically provides an arming signal to the Steam Dump System. On decreasing reactor coolant loop temperature, P-12 automatically removes the arming signal from the Steam Dump System. P-14 On increasing steam generator water level, P-14 automatically trips all feedwater isolation valves, main feed pumps and main turbine, and inhibits feedwater control valve modulation. 314.3.3 MONITORING INSTRUMENTATION 3/4.3.3.1 RADIATION MONITORING FOR PLANT OPERATIONS The OPERABILITY of the radiation monitoring instrumentation for plant operations ensures that: (1) the associated action will be initiated when the radiation level monitored by each channel or combination thereof reaches its Setpoint, (2) the specified coincidence logic is maintained, and (3) sufficient redundancy is maintained to permit a channel to be out-of-service for testing or maintenance. The radiation monitors for plant operations senses radiation levels in selected plant systems and locations and determines whether or not predetermined limits are being exceeded. If they are, the signals are combined into logic matrices sensitive to combinations indicative of various accidents and abnormal conditions. Once the required logic combination is completed, the system sends actuation signals to initiate alarms. 3/4.3.3.2 DELETED 3/4.3.3.3 DELETED 3/4.3.3.4 DELETED MILLSTONE - UNIT 3 B 314 3-4 Amendment No. A9, 219

INSTRUMENTATION BASES 3/4.3.3.5 REMOTE SHUTDOWN INSTRUMENTATION The OPERABILITY of the Remote Shutdown Instrumentation ensures that sufficient capability is available to permit safe shutdown of the facility from locations outside of the control room. This capability is required in the event control room habitability is lost and is consistent with General Design Criterion 19 of 10 CFR Part 50. Calibration of the Intermediate Range Neutron Amps channel from Table 4.3-6 applies to the signal that originates from the output of the isolation amplifier within the intermediate range neutron flux processor drawers in the control room and terminates at the displays within the Auxiliary Shutdown Panel. The OPERABILITY of the Remote Shutdown Instrumentation ensures that a fire will not preclude achieving safe shutdown. The remote shutdown monitoring instrumentation, control, and power circuits and transfer switches necessary to eliminate effects of the fire and allow operation of instrumentation, control and power circuits required to achieve and maintain a safe shutdown condition are independent of areas where a fire could damage systems normally used to shut down the reactor. This capability is consistent with General Design Criterion 3 and Appendix R to IO CFR Part 50. 3/4.3.3.6 ACCIDENT MONITORING INSTRUMENTATION The OPERABILITY of the accident monitoring instrumentation ensures that sufficient information is available on selected plant parameters to monitor and assess these variables following an accident. The instrumentation included in this specification are those instruments provided to monitor key variables, designated as Category 1 instruments following the guidance for classification contained in Regulatory Guide 1.97, Revision 2, "Instrumentation for Light-Water-Cooled Nuclear Power Plants To Assess Plant and Environs Conditions During and Following an Accident." MILLSTONE - UNIT 3 B 3/4 3-5 Amendment No. 3, 46, 4, I44, 219

LBDCR No. 04-MP3-015 February 24, 2005 INS7RUWMATION BASES 314.3.3.6 ACC1DENT MONrMOd INSIRUMEWrATION (Continued) ACTION Statement -a": I The use of one main control board indicator and one computer point, total of two indicators per steam generator, meets the requirements for the total number of channels for Auxiliary Feedwater flow rate. The two channels used to satisfy this Technical Specification for each steam generator are as follows: team Instmment tMBS\ bnstumenitmper) 01 FWA*FISlA1 (Orange) FWA-F33A3 (uple) S2 FWA*F133BI (Piuple) FWA - FSlB3 (Orange) 03 FWA*F133C1 (Purpl) FWA - F5IC (Orange) 04 FWA*F551DI (Orange) FWA-F33D3 (PrPle) The SPDS computer point for auxiliary feedwater flow will be lost 30 minutes following an LOP when the power supply for the plant computer is lost. However, tis design configuration - one continuous main control board indicator and one indication via the SPDSlplant computer, total oftwo per steam generator - was submitted to the NRC via "Response to question 420.6" dated January 13, 1984, B 11002. NRC review and approval was obtained with the acceptance of MP3, SSER 4 Appendix L, "Conformance to Rcgulatory Guide 1.97," Revision 2. (dated November 1985). LCO 3.3.3.6, Table 3.3-10, Item (17), requires 2 OPERABLE reactor vessel water level I (heated junction thermocouples - HJC) channels. An OPERABLE reactor vessel water level channel shall be defined as: .

1. Four or more total sensors operating.

• 2. At east one oftwo operatng sensors in theupperhead.

3. At least thru: of six operating sensors intheupper plenum.

MILLSTONE - UNIT 3 B 3/4 3-5a Amendment No. -, 6,84, 4 0, p fiD (QJ4Sy@,t L,-@5 - 5-9 %

LBDCR No. 04-MP-015 February 24, 2005 INSTRUMENTATION BASES U4,33.6 ACCIDEINT MONMTR 4MENTATl0N (Continued) A channel is OPERABLE if four or more sensors, half or more in the upper head region and half or more in the upper plenum region, are OPERABLE In the event more than four sensors in a Reactor Vessel Level channel are inoperable, repairs may only be possible during the next refueling outage. This is because the sensors re accessible only after the missile shield and reactor vessel head are removed. It is not feasible to repair a channel except dring a refueling outage when the missile shield and reactor vessel head arc removed to refuel the core. If only one channel is inoperable, it should be restored to OPERABLE status in a refueling outage as soon as reasonably possible. If both channels are inoperable, at least one channel shall be restored to OPERABLE status in the nearest refueling outage. The Reactor Coolant System Subcooling Margin Monitor, Core Exit Thermocouples, and Reactor Vessel Water Level instruments are processed by two separate trains of ICC (Inadequate Core Cooling) and HJTC (Heated JunctionThermoCouple) processors. The preferred indication for these parameters is the Safety Parameter Display System (SPDS) via the non-qualified PPC (Plant Process Computer) but qualified indication is provided in the instrument rack room. When the PPC data links cease to ransmit data, the processors must be reset in order to restore the flow of data to the PPC. During reset, the qualified indication in the instrument rack room is lost. These instruments are OPERABLE during this reset since the indication is only briefly interrupted while the processors reset and the indication is promptly restored. The sensors are not removed fErm service during this reset. The train should be considered inoperable only ifthe qualified indication fais to be restored following reset. Except for the non-qualified PPC display, the instruments operate as required. Hydrogen Monitors are provided to detect high hydrogen concentration conditions that represent a potential for containment breach fiom a hydrogen explosion. Containment hydrogen concentration is also important in verifyB4 the adequacy of mitigating actions. The requirtmet to perform a hydrogen sensor calibration at least once every 92 days is based upon vendor recomnmendations to maintain sensor calibration. This calibration consists of a two point calibration, utiiig gas containing pproximately one percent hydrogen gas for one of the calibtion points, and gas containing approximately four percent hydrogen gas for the other calibrationpoint. 314.3,3.7 DELETED 3/4.3.3.9 DELETED 3/4.3.3.10 DELETE MILLSTONE - UNIT 3 B 3/4 3-6 AmendmentNo.488, 4i, , 2c0S)C hai1j 6& -QG;

LBDCR No. 04-MP3-01S February 24,2005 WNSjRUAf0NlTnN BASES 3/4.3.5 TSHUTDOWN MARGIN MONITOR The Shutdown Margin Monitors provide an alarm that a Boron Dilution Event may be in pogress. The mmimum countrate of Specification 3/43.5 and the SHUTDOWN MARGIN requirements specified in the CORE OPERAIING LIMITS REPORT for MODE 3, MODE 4 and MODE S ene that at leas 15 minutes are available for operator action from the time of the Shutdown Man Monitor alarm to total loss of SHUTDOWN MARGIN. By borating an additional 150 ppm above the SHUTDOWN MARGIN specified in the CORE OPERA:1NG IMAITS REPOR forMODE 3 r 350 ppm above the SHUTDOWN MARGIN specified in the CORE OPERATING LIMITS REPORT for MODE 4, MODE 5 with RCS loops filled, or MODE 5 with RCS loops not filled, lower values of minimum count rate are accepted. Shutdown Margin Monitors BAckmerund. The purpose of thie Shutdon Margin Monitors (SMM) is to annunciate an increase in core subcritical mul plication allowing the operator at least 15 minutes response time to mitigate the consequences oflhe inadvertent addition ofunborated primary grade water (boron dilution event) into t Reactor Coolant System (RCS) when the reactor is shut down (MODES 3,4, and 5). The SMMs utilizes two channels of source range instrumentation (GM detectors). Each channel provides a signal to its applicable train of SML The SMM channel uses the last 600 or more counts to calculate the count rate and updates the measurement after 30 new counts or I second, whichever is longer. Each channel has 20 registers that hold the counts (20 registers X 30 coumt 600 couts) for av g the rate. As the count rate decreascs, the longer it taes to fill the resters (fill te 30 count nimum). As the Instrument's measured count rate decreases, the delay time in the Instumets response increases. This delay time leads to tIe reqirment of a inru count rate for OPERABILIIY. During the dilution event, count rate will increase to a level above the normal steady state count rate. When this new count rate level increases above the instrumentes setpoint, the channed will alarm alerting the operator of the event. Apuligble Safety Analysis The SMM senses abnormal Increases in the sou range count per second and alarms the operator of an inadvertent dilution event. This alarm will occur at least 15 minutes prior to the reactor achieving criticality. This 15 minute window allows adequate operator response time to terminate the dilution, FSAR Section 15A.6. LCO33.5 provides the reqirements for OPERABILITY of theinstrumentation of the SMMs that are used to mitigate te boron dilution event. Two trains are required to be OABLE to provide protection against single failure. MILLSTONE - UNIT 3 B 3/4 3-7 Amendment No. 464,

• LBDCRNo. 04-MP3-015 February 24, 2005 BASES (continued)

Applicability The SMM must be OPERABLE in MODES 3,4, and 5 because the safety analysis identifies this system as the primary means to alert the operator and mitigate the event. The SMMs are allowed to be blocked during start up activities inMODE 3 in accordance with approved plant procedures. The alarm is blocked to allow the SMM channels to be used to monitor the 1IN approach to criticality. The SMM are not required to be OPERABLE in MODES I and 2 as other RPS is credited with accident mitigation, over temperature delta temperature and power range neutron flux high (low setpoint of 25 percent RTP) respectively. The SMMs are not required to be OPERABLE in MODE 6 as the dilution event is precluded by administrative controls over all dilution flow paths (Technical Specification 4.1.1.22). A-ONS Channel inoperability of the SMds can be caused by failure of the channel's electronics, failure of the channel to pass its calibration procedure, or by the channel's count rate falling below the minimum count rate for OPERABILITY. This can occur when the count rate is so low that the channel's delay time is in excess of that assumed in the safety analysis. In any of the above conditions, the channel must be declared inoperable and the appropriate ACTION statement entered. If the SMMs are declared inoperable due to low count rates, an RCS heatup will cause the SMM dhannel count rate to Increase to above the minimum count rate for OPERABILITY. Allowing the plant to increase modes will actually return the SMMs to OPERABLE status. Once the SMM channels are above the minimum count rate for OPERABILlT', the channels can be declared OPERABLE and the LCO ACTION statements can be exited. LCO 33.5, ACTION a. - With one train of SMM inoperable, ACTION a. requires the inoperable train to be returned to OPERABLE status within 48 hours2 days <br />0.286 weeks <br />0.0658 months <br />. In this condition, the remaining SMM train is adequate to provide protection. If the above rquired ACTION cannot be met, alternate compensatory actions must be performed to provide adequate protection from the boron dilution event. All operations involving positive reactivity changes associated with RCS dilutions and rod withdrawal must be suspended, and all dilution flowpaths must be closed and secured In position (locked closed per Technical Specification 4.1.12.2) within the following 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />. LCO 33.5, ACIION b. -With both trains of SMM inoperable, altermate protection must be provided:

1. Positive reactivity operations via dilutions and rod withdrawal are suspended. The intent ofthis ACTION is to stop any planned dilutions ofthe RCS. The SoMs are not intended to monitor core reactivity during RCS temperature changes. The alarm setpoint is routinely reset during the plant heatup due to the increasing count rate. During cooldowns as the count rate decreases, baseline count rates are continually lowered automatically by the SMMs. TheMilstoneUnitNo. 3 boron dilution analysis assumes steady stateRCS temperature conditions.

MILLSTONE - UNIT 3 B 314 3-8 Amendment No. 464,

LBDCR No. 04-MP3-015 Februay 24,2005 BASES (continued)

2. All dilution flowpaths are isolated and placed under administrative control (locked closed). This action provides redundant protection and defense in depth (safety overlap) to the SMMs. In this configuration, a boron dilution event (BDE) cannot occur. This is the basis fornothaving to analyze forBDE inMODE 6. Since the BDE cannotoccurwith the dilution flow paths isolate4 the SMMs are not required to be OPERABLE as the event cannot occur and OPERABLE SUMs provide no benefit.

3. Increase the SHUTDOWN MARGIN surveillance frequency from every 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> to every 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />. This action in combination with the above, provide defense in depth and overlap to the loss of the SbMs.

LSuveilance Remuirements The SMs are subject to an ACOT every 92 days to ensure each train of SMM is folly operational. This test shall include veification that the SMMs areset per the CORE OPERATING LMITS REPORT. I MILLSTONE - UN1T 3 B 3M43-9 Amendment No.464, 4J& vav(-- Cd -9S

LEDCRNo. 04-MP3-015 February 24, 2005 3/4.4 REACTOR COOLANT SYSTEM BASES 3/4.4.1 -REACTOR COOLANT LOOPS AND COOL^ANT-0RCULATION Thepurpose of Specification 3.4.1.1 is to require adequate forced flow rate for core heat removal in MODES I and 2 during all normal operations and anticipated transients. Flow is represented by the number of reactor coolant pumps in operation for removal of heat by the steam generators. To meet safety analysis acceptance criteria for DNB, four reactor coolant pumps are required at rated power. An OPERABLE reactor coolant loop consists of an OPERABLE reactor coolant pump in operation providing forced flow for heat transport and an OPERABLE steam generator in accordance with Specification 3AS. With less than the required reactor coolant loops in operation this specification requires that the plant be in at least HOT STANDBY within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />. In MODE 3, three reactor coolant loops, and in MODE 4, two reactor coolant loops provide sufficient heat removal capability for removing core decay heat even in the event of a bank withdrawal accident; however, in MODE 3 a single reactor coolant loop provides sufficient heat removal capacity ifa bank withdrawal accident can be prevented, i.e, the Control Rod Drive System is not capable of rod withdrawal In MODE 4, if a bank withdrawal accident can be prevented, a single reactor coolant loop or RHR loop provides sufficient heat removal capability for removing decay heat; but single failure considerations require that at least two loops (any combination of RHR or RCS) be OPERABLE. In MODE S, with reactor coolant loops filled, a single RHR loop provides sufficient heat removal capability for removing decay heat; but single filure considerations require that at least two RHR loops or at least one RHR loop and two steam generators be OPERABLE. In MODE S with reactor coolant loops not filled, a single RHR loop provides sufficient heat removal capability for removing decay heat; but single failure considerations, and the unavailability of the steam generators as a heat removing component, require that at least two RHR loops be OPERABLE. In MODE S, during a planned heatup to MODE 4 with all RHR loops removed from operation, an RCS loop, OPERABLE and in operation, meets the requirements of an OPERABLE and operating RHR loop to circulate reactor coolant During the heatup there is no requirement for heat removal capability so the OPERABLE and operating RCS loop meets all of the required fimctions for the heatup condition. Since fiilure of the RCS loop, which is OPERABLE and operating, could also cause the associated steam generator to be inoperable, the associated steam generator cannot be used as one of the steam generators used to meet the requirement of LOO 3A.4.4.1.b. MILLSTONE - UNIT 3 B 3/4 4-1 Amendment No. 69, 0, 99, 4*, 49i,

LBDCR No. 04-MP3-015 February 24, 2005 314A REACTOR COOLANT SYSTEM BASES (Continued) The operation of one reactor coolant pump (RCP) or one RHR pump provides adequate flow to ensure mixing, prevent statification and produce gradual reactivity changes during boron concentration reductions in the Reactor Coolant System. The reactivity change rate associated with boron reduction will, therefore, be within the capability of operator recognition and control. The restrictions on starting the first RCP in MODE 4 below the cold overpressure protection enable temperature (2260F), and in MODE S am provided to prevent RCS pressure transients. These transients, energy additions due to the differential temperature between the steam generator secondary side and the RCS, can result in pressure excursions which could challenge the P/r limits. The RCS will be protected against overpressure transients and will not exceed the reactor vessel isothermal beitline P/T limit by restricting RCP starts based on the differential water temperature between the secondary side of each steam generator and the RCS cold legs. The restrictions on starting the first RCP only apply to RCPs in RCS loops that are not isolated The restoration of isolated RCS loops Is normally accomplished with all RCPs secured. If an isolated RCS loop is to be restored wien an RCP is operating, the appropriate temperature differential limit between the secondary side of the isolated loop steam generator and the in service RCS cold legs is applicable, and shall be met prior to opening the loop isolation valves. The temperature differential limit between the secondary side of the steam generators and the RCS cold legs is based on the equipment providing cold overpressure protection as required by Technical Specification 3.4.93. If the pressurizer PORVs are providing cold overpressure protection, the steam generator secondary to RCS cold leg water temperature differential is limited to a maximum of 500F. If any RHP relief valve is providing cold overpressure protection and RCS cold leg temperature is above I 501 0 F, the steam generator secondary water temperature must be at or below RCS cold leg water temperature. If any RHR reliefvalve is providing cold overpressure protection and RCS cold leg temperature is at or below 1500F, the steam generator secondary to RCS cold leg water temperature differential inlimited to a maximum of 50F. Specification 3A.1.5 The reactor coolant loops are equipped with loop stop valves that permit any loop to be isolated from the reactor vesseL One valve is installed on each hot leg and one on each cold leg. The loop stop valves are used to perform maintenance on an isolated loop. Operation in MODES 1-4 with a RCS loop stop valve closed is not permitted except for the mitigation of emergency or abnormal events. If a loop stop valve Is closed for any reason, the required ACTIONS of this specification must be completed. To ensure that inadvertent closure of a loop stop valve does not occur, the valves must be open with power tothe valve operators removed inMODES 1, 2,3 and 4. MILLSTONE-UNIT 3 B 314 4-la Amendment No.60, ;0 99, 4%, 49, BI, #*, Alto~~M v2< g$<4n

• LBDCR No. 04-W3-015 February 24,2005 314.4 REACTOR COOLANT SYSTEM BASES The safety analyses performed for the reactor at power assume that all reactor coolant loops are initially in operation and the loop stop valves are open. This LCO places controls on the loop stop valves to ensure that the valves are not inadvertently closed in MODES 1, 2, 3 and 4.

The inadvertent closure of a loop stop valve when the Reactor Coolant Pumps (RCPs) are operating will result in a partial loss of forced reactor coolant flow. If the reactor is at rated power at the time of the event, the effect of the partial loss of forced coolant flow is a rapid increase in the coolant temperature which could result in DNB with subsequent fuel damage if the reactor is not tripped by the Low Flow reactor trip. If the reactor is shutdown and a RCS loop is in operation removing decay heat, closure of the loop stop valve associated with the operating loop could also result in icreasing coolant temperature and the possibility of fuel damage. The loop stop valves have motor operators. Ifpower is inadvertently restored to one or more loop stop valve operators, the potential exists for accidental closure ofthe affected loop stop valve(s) and the partial loss offorced reactor coolant flow. With power applied to a valve operator, only the interlocks prevent the valve from being operated. Although operating procedures and interlocks make the occurrence of dhis event unlikely, the prudent action is to remove power from the loop stop valve operators. The time period of 30 minutes to remove power from the loop stop valve operators is sufficient considering the complexity of the task Should a loop stop valve be closed In MODES 1 through 4, the affected valve must be maintained closed and the plant placed in MODE 5. Once in MODE 5, the isolated loop may be started in a controlled manner in accordance with LCO 3A.1.6, "Reactor Coolant System Isolated Loop Startup." Opening the closed loop stopPvalve in MODES I through 4 could result in colder water or water at a lower boron concentration being mixed with the operating RCS loops resulting in positive reactivity insertion. The time period provided in ACIZON 3A.1 .5.b allows time for l borating the operating loops to a shutdown boration level such that the plant can be brought to MODE 3 witin 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and MODES within 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />. The allowed ACTION times are reasonable, based on operating experience, to reach the required plant conditions fiom full power conditions in an orderly manner and without challenging plant systems. Surveillance Requirement 4A.1.5 Is prformed at least once per 31 days to ensure that the RCS loop stop valves are open, with power removed from the loop stop valve operators. The primary finction of Uhis Surveillance is to ensue that power is removed firm the valve operators, since Surveillance Requirement 4A.1.1 requires verification every 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> that all loops are operating and circulating reactor coolant, thereby ensuring that the loop stop valves are open. The frequency of 31 days ensures that the required flow is available, is based on engineering judgement, and has proven to be acceptable. Operating experience has shown that the failure rate is so low that the 31 day freq yencis justified. MILLSTONE - UNIT 3 B 314 4-lb Amendment No. 60, , K, 4 ,4*9, Ave A24rk

LBDCR No. 04-MP3-015 February 24,2005 314.4 REACTOR COOLANT SYSTEM BASES (Continued) Specification 3.4.1.6 The requirement to maintain the Isolated loop stop valves shut with power removed ensures that no reactivity addition to the core could occur due to the startup of an isolated loop. Wrification of the boron concentration in an isolated loop prior to opening the firlt stop valve povides a reassurance of the adequacy oftheboron concentration in the isolated loop. RCS Loops Filled/Not Filled In MODE 5, any RHR train with only one cold leg injection path is sufficient to provide adequate core cooling and prevent stratification of boron in the Reactor Coolant System. The definition of OPERABLUY states that the system or subsystem must be capable of j performing its specified function(s). The reason for the operation of one reactor coolant pump (RCP)or one RHR pump isto:

• Provide sufficient decay heat removal capability
• Provide adequate flow to ensure mixing to:
• Prevent stratification
• Produce gradual reactivity changes due to boron concentration changes in the RCS The definition of eactor coolant loops filled" includes a loop that is filled, swept, and vented, and capable of supporting natural circulation heat transfer. This allows the non-operating RHR loop to be removed from service while filling and unisolating loops as long as steam generators on the OPERABLE reactor coolant loops are available to support decay heat removal.

Any loop being unisolated is not OPERABLE until the loop has been swept and vented. The process of sweep and vent will make the previously OPERABLE loops inoperable and the requirements of LCO 3A.1.42, 'Reactor Coolant System, COLD SHUTDOWN - Loops Not Filled a applicable, When the RCS has been filled, swept and vented using an approved procedure, all unisolated loops may be declaied OPERABLE. One cold leg injection isolation valve on an RHR train may be closed without considering the train to be inoperable, as long as the following conditions exist:

• CCP temperaturc is at orbelow 950F
• Initial RHR temperature is below 184°F MILLSTONE - UNIT 3 B 314 4-1c Amendment No. 4*,

LBDCR04-MP3001 314.4 R]ACTORQOOMAM TY BASS (Continued)

• Thc sigle PMR codIajcction flow pathi s nol utilized unti aam um of24 houw ater reactor m
• RHRflo*ls at lcast2,000 gpm

                         * -.                e.         'Ib           t ***      *'*         9 4       'heflowwn two cold legs are In seM Tis6k is 6c4a£6 duc6It                                         6tt1iiihgii          theL Aowm required for cQoing and the flow ayalloa, ec t .ou01 a                       ighrtl                   W !              . .t
            -a                * *   ^fiai%~aii                              oE ofa %~AL                       f       X-In;nfits*^:~sf#                 gfc              t      the .lo*xat orliserti3it1                    6  -         ;

corDso,Ih noiznbin io fic , ..

                                                                                               -..        -      4,;

Flow vedty, whishisb, is not a conc fim a flow erosionoc plog~ng . standpoint. There arm no loads sd on the pipng stem which wodieA i.h&

• experienced Ina se~smid CvC; The.em pf fuid

                                                                 ~he is tog.d ptgz~i.cgL        9                fii~m a flow erosdon ot&                   '   , *-                            .      .*.

The boron dilution accident anadysis, for Millstone Unit 3 ni MOb 51si; DHR.Sysjc flow ofz.pproxhlu~y 4,QOpsxL id wousefmn~ly,. _Rfeczq.cf(9 rtR flows &vnidp h. a R[ GivI.,i*U y diluti~hoddn iP .; . .- t lhe hiatis fo ~thereiiqtnM bE tw lqS ojs9 toi.~dar4, c~cuiriaon hiabii&nheith +:i @ f tet.rr!~o;S two loops sweptand venteddtoloopsairbound, sturic l eblishd i the two swCptl... -..-

                                                          ..    .ir1a                  Ia.             tqietp 1vou3qe nockhfi fro~,ed                        Arifo,,o                                               soo~tbe camied to the vesselt and subsiily               6e sivf loboMrihg&her&'lmt                                 6         fat Ain Tequirtments.

• Ihe LCO is met as long as at least two zeactor cool l6ps are OPiEbLINa the following coinditions ae safied.
• One RHR loop is OPMABLE and in opeation, with exceptions asilfed in Tecbical Specifications; and MILLSTON - UNIT 3 B 314 4-1d AmendmentNp,-M, Iaao Oha44yP e ?-&6 &62X-

3/4.4 REACTOR COOLANT SYSTEM BASES (Continued) The LCO is met as long as at least two reactor coolant loops are OPERABLE and the following conditions are satisfied:

• One RHR loop is OPERABLE and in operation, with exceptions as allowed in Technical Specifications; and Either of the following:
• An additional RHR loop OPERABLE, with exceptions as allowed in Technical Specifications; or
• The secondary side water level of at least two steam generators shall be greater than 17% (These are assumed to be on OPERABLE reactor coolant loops)

When the reactor coolant loops are swept, the mechanism exists for air to be carried into previously OPERABLE loops. All previously OPERABLE loops are declared inoperable and an additional RHR loop is required OPERABLE as specified by LCO 3.4.1.4.2 for loops not filled. When the RCS has been filled, swept, and vented using an approved procedure, all unisolated loops may be declared OPERABLE. ISOLATED LOOP STARTUP The below requirements are for unisolating a loop with all four loops isolated while decay heat is being removed by RHR and to clarify prerequisites to meet T/S requirements for unisolating a loop at any time. With no RCS loops operating, the two RHR loops referenced in Specification 3.4.1.4.2 are the operating loops. Starting in MODE 4 as referenced in Specification 3.4.1.3, the RHR loops are allowed to be used in place of an operating RCS loop. Specification 3.4.1.4.2 requires two RHR loops OPERABLE and at least one in operation. Ensuring the isolated cold leg temperature is within 20'F of the highest RHR outlet temperature for the operating RHR loops within 30 minutes prior to opening the cold leg stop valve is a conservative approach since the major concern is a positive reactivity addition. SR 4.4.1.6.1: When in MODE 5 with all RCS loops isolated, the two RHR loops referenced in LCO 3.4.1.4.2 shall be considered the OPERABLE RCS loops. ISOLATED LOOP STARTUP (Continued) The isolated loop cold leg temperature shall be determined to be within 20'F of the highest RHR outlet temperature for the operating RHR loops within 30 minutes prior to opening the cold leg stop valve. Surveillance requirement 4.4.1.6.2 is met when the following actions occur within 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> prior to opening the cold leg or hot leg stop valve:

• An RCS boron sample has been taken and analyzed to determine current boron concentration
• The SHUTDOWN MARGIN has been determined using OP 32098, "Shutdown Margin" using the current boron concentration determined above
• For the isolated loop being restored, the power to both loop stop valves has been restored MILLSTONE - UNIT 3 B 3/4 4-Id Amendment No. 217 0987

                                 *       -LBD                                         04-MP30021 March25, 2004 314A REACrOR CO01 BAMS (continued)

• For the isolated loop being restored, the power to both loop stop valves has been restored Surveillance 4A.1.6.2 indicates that the reactor shall bi determined suboritical byat least the amount required by Specifications 3.1.1.1.2 or 3.1.1.2 for MODE 5 or Specification 3.9.1.1 forMODE 6 Wlthin2hours of openngthecoldlegorhotleg stop valve.

The SHUIDOWN MARGIN requirement in SpecIfication 3.1.1.1.2 is specified la the Core OpmatingLmlts Report forMODBS wihRCS loops filled. Specification 3.1.1.1.2 cannot be used to deterine the required SHUTDOWN MARGIN for MODB 5 loops isolated condition. Spcification 3.1.12 requires the SHUTDOWN MARGIN to be greater than or equal to the limits specified in the Core Operating IlSts Report for MODE 5 with RCS loops not filled provided CVCS Isaliged to preclude boron dilution. i specification is for loops not filled and therefore Is applicable to an all loops isolated conditon. Specification 3.9.1.1 requires KLrof0.95 or less, oraboron concentration of greater than or equal to the Eik specified in the COLR n MODE 6. Specification 3.1.1.12 or 3.1.12 forMODE 5,both require boron concentration to be detennfind at least once each 24 hours1 days <br />0.143 weeks <br />0.0329 months <br />. SR 4.1.1.l2.1.b.2 and 4.1.12.lb.1 satisl*' the requireenats of Specifications 3.1.1.1.2 and 3..1.2respectfiully. Specification 3.9.1.1 for MODE 6 requires boron concentration to be determined at least once each 72 hours3 days <br />0.429 weeks <br />0.0986 months <br />. SIL 4.91.1.2 satisfy the reqdirements of Specification 3.9.1.1.

References:

1. Letter NEU-94-623, dated July 13, 1994; Mixing Evalation for BoronDflution Accident in Modes 4 and 5, Westinghouse HR-59782.

2. Memo No. M3-E-93-821, dated October 7,1993.

MILLSTONE-UNIT3 B 314 4-If AmendmentNo. 4-,

                                                          &       f     (c    u-_           'S      -

LBDCR No. 04-MP3-015 February 24, 2005 REACJQR COOLANT SYSTEM BASES 314A.2 SAETY-VALVES The pressurizer Code safety valves operate to prevent the RCS from being pressurized above its Safety Limit of 2750 psia. Each safety valve is designed to relieve 420,000 lbs per hour of saturated steam at the valve Setpoint The reliefcapacity of a single safety valve is adequate to relieve any overpressure condition which could occur during shutdown. If any pressurizer Code safety valve is inoperable, and cannot be restored to OPERABLE status, the ACTON statement requires the plant to be shut down and cooled down such that Teclmical Specification 3.4.9.3 will become applicable and require cold overpressure protection to be placed in service. During operation, all pressurizer Code safet valves must be OPERABLE to prevent the RCS fiom being pressurized above Its Safety Limit of 2750 psia. The combined reliefcapacity of all ofthese valves Is greater than the maximum surge rate resulting from a complete loss-of-load assuming no Reactor trip until the first Reactor Trip System Trip Setpint Isreached (.e., no credit Istaken for a direct Reactor trip on the loss-of-load) and also assuming no operation of the power-operated relief valves or steam dump valves. Demonstration of the safety valves' lift settigs vngil occur only during shutdown and will be performed in accordance with the provisions of Section Xi of the ASME Boiler and Pressure Code. 314.4.3 PRESSURI2ER The pressurizer provides a point inthe RCS when liquid and vapor are maintained in equilibrium under saturated conditions for pressure control purposes to prevent bulk boiling in the remainder of the RCS. Key fimctions include maintaining required primary system pressure during steady state operation and limiting the pressure changes caused by reactor coolant thermal expansion and contraction during load transents. MODES I AND 2

         'he requirement for the pressuriz to be OPERABLE, with pressurizer level maintained at programmed level within WS%      of full scale is consistent with the accident analysis InChapter 15 of the FSAR. The accident analysis assumes that pressurizer level is being maintained at the programmed level by the automatic control system, and when in manual control, similar limits are established. The programmed level ensures the capability to establish and maintain pressure control for steady state operation and to minimize the consequences of potential overpressure and pressurizer overfill transients. A pressurizer level control error based upon automatic level control has been taken Into account for those transients where pressurizer overfill is a concern (e.g., loss offeedwater, feedwater line breac, and inadvertent EQCS actuation at power). When in manual control, the goal isto maintain pressurizer level at the program level value. The :h 6 % of full scale acceptance criterion in the Technical Specification establishes a band for operation to accommodate variations between level measurements. This value is bounded by the margin applied to the pressurizer overfill events.

MILSTONE - UNIT 3 B 3/4 4-2 AmendmentNo.460,497, 6aow haeigrs&69- 95 &6bz

KtAUIUK LUULAN I b r b Itr BASES 3/4.4.3 PRESSURIZER (cont'd.) The 12-hour periodic surveillances require that pressurizer level be maintained at programmed level within + 6% of full scale. The surveillance is performed by observing the indicated level. The 12-hour interval has been shown by operating practice to be sufficient to regularly assess level for any deviation and to ensure that the appropriate level exists in the pressurizer. During transitory conditions, i.e., power changes, the operators will maintain programmed level, and deviations greater than 6% will be corrected within 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br />. Two hours has been selected for pressurizer level restoration after a transient to avoid an unnecessary downpower with pressurizer level outside the operating band. Normally, alarms are also available for early detection of abnormal level indications. Electrical immersion heaters, located in the lower section of the pressurizer vessel, keep the water in the pressurizer at saturation temperature and maintain a constant operating pressure. A minimum required available capacity of pressurizer heaters ensures that the RCS pressure can be maintained. The capability to maintain and control system pressure is important for maintaining subcooled conditions in the RCS and ensuring the capability to remove core decay heat by either forced or natural circulation of the reactor coolant. Unless adequate heater capacity is available, the hot high-pressure condition cannot be maintained indefinitely and still provide the required subcooling margin in the primary system. Inability to control the system pressure and maintain subcooling under conditions of natural circulation flow in the primary system could lead to a loss of single-phase natural circulation and decreased capability to remove core decay heat. The LCO requires two groups of OPERABLE pressurizer heaters, each with a capacity of at least 175 kW. The heaters are capable of being powered from either the offsite power source or the emergency power supply. The minimum heater capacity required is sufficient to maintain the RCS near normal operating pressure when accounting for heat losses through the pressurizer insulation. By maintaining the pressure near the operating conditions, a wide margin to subcooling can be obtained in the loops. The requirement for two groups of pressurizer heaters, each having a capacity of 175 kW, is met by verifying the capacity of the pressurizer heater groups A and B. Since the pressurizer heater groups A and B are supplied from the emergency 480V electrical buses, there is reasonable assurance that these heaters can be energized during a loss of offsite power to maintain natural circulation at HOT STANDBY. Providing an emergency (Class 1E) power source for the required pressurizer heaters meets the requirement of NUREG-0737, "A Clarification of TMI Action Plan Requirements," II.E.3.1, "Emergency Power Requirements for Pressurizer Heaters." If one required group of pressurizer heaters is inoperable, restoration is required within 72 hours3 days <br />0.429 weeks <br />0.0986 months <br />. The Completion Time of 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> is reasonable considering that a demand caused by loss of offsite power would be unlikely in this time period. Pressure control may be maintained during this time using normal station powered heaters. MODE 3 The requirement for the pressurizer to be OPERABLE, with a level less than or equal to 89%, ensures that a steam bubble exists. The 89% level preserves the steam space for pressure control. The 89% level has been established to ensure the capability to establish and maintain pressure control for MODE 3 and to ensure a bubble is present in the pressurizer. Initial pressurizer level is not significant for those events analyzed for MODE 3 in Chapter 15 of the FSAR. MILLSTONE - UNIT 3 B 3/4 4-2a Amendment No. Xfo, 210 0816 AUG 2 6 1

LBDCR No. 04-MP3-015 February 24,2005 REACTOR COOL ANT SYSTEM BASES 314.4 3 P IRFSSURIZER (cont'de  ! The 12-hour periodic surveillance requires that during MODE 3 operation, pressurizer level is maintained below the nominal upper limit to provide a munimum space for a steam bubble. The surveillance isperformed by observing the indicated level. The 12-hour interval has been shown by operating practice to be sufficient to regularly assess level for any deviation and to ensure that a steam bubble exists in the pressurizer. Alarms are also available for early detection of abnormal level indications. The basis for the pressurizer heater requirements is identical to MODES I and 2. 3/4.4.A RELIEP VALVES The power-operated reliefvalves (PORVs) and steam bubble fincdon to relieve RCS pressure during all design transients up to and including the design step load decrease with steam dump. Operation ofthe PORVs minimizes tIe undesirable opening ofthe spring-loaded pressurir Code safety valves. Each PORV has a remotely operated block valve to provide a positiv~e shutoffcapability should a relief valve become inoperable Requiring the PORts to be OPERABLE ensures that the capability for depressurization during safety grade cold shutdown is rneL ACTlON statements a, b, and c distinguishes the inoperability of the power operated relief'valves (PORV). Specifically, a PORV may be designated inoperable but it may be able to automatically and manually open and close and therefore, able to perforin its fimction. PORV inoperability may be due to seat leakage which does not prevent automatic or manual use and does not create the possibility for a small-break LOCA. For these reasons, the block valve may be closed but the action requires power to be maintained to the valve. This allows quick access to the PORV for pressure control. On the other hand if a PORV I inoperable and not capable of being automatically and manually cycled, it must be either restored or isolated by closing the associated block valve and removing power Note: PORV position indication does not affect the ability of the PORV to perform any of its safety functions. Therefore, the failure of PORV position indication does not cause the PORV to be inoperable. However, failed position Indication of these valves must be restored 'as soon as practicable" as requiredbylclcal Specification 6.8A.e3. Automatic operation of the PORVs is created to allow more time for operators to terminate an Inadvertent ECCS Actuation at Power. Mem PORVs and associated piping have been demonstrated to be qualified for water relief. Operation of the PORVs will prevent water relief from the pressurer safety valves for which qualification for water relief has not been demonstrated. If the POXVs art capable of automatic operation but have been declared inoperable, closure of the PORV block valve Isacceptable since the Emergency Operating Procedures provide guidance to assure that the PORVs would be available to mitigate the evenL OPERABILITY and setpoint controls for the safety grade PORV opening logic are maintained in the Technical Requirements Manual. MILLSTONE - UNIT 3 B 3/4 4-2b Amendment No. 460,4(4 RAfe Cba- g

LBDCRNo. 04-MP3-015 February 24,2005 REACTOR COOLANT SYSTEM BASES RELTYF VALVES (Continue) The prime importance for the capability to close the block valve is to isolate a stuck-open PORV. Therefore, if the block valvs) cannot be restored to OPERABLE status within I hour, the remedial action is to place the PORV in manual control (ie. the control switch in the "CLOSE" I position) to preclude its automatic opening for an overpressure event and to avoid the potential of a stuck-open POR at a time that the block valve is inoperable. The time allowed to restore the block valve(s) to OPERABLE status is based upon the remedial action time limits for inoperable PORV per ACTION requiments b. and c. ACTION statement d. does not specify closure of the block valves because such action would not likely be possible when the block valve is inoperable. I For the same reasons, reference is not made to ACTION statements b. and c. for the required I remedial actions. MILLSTONE - UNIT 3 B 314 4-2c Amcndment No. 8B,460,464, J 6 C  % . : i5 -- bb5 b

REACTOR COOLANT SYSTEM BASES 3/4.4.5 STEAM GENERATORS The Surveillance Requirements for inspection of the steam generator tubes ensure that the structural integrity of this portion of the RCS will be main-tained. The program for inservice inspection of steam generator tubes is based on a modification of Regulatory Guide 1.83, Revision 1. Inservice inspection of steam generator tubing is essential in order to maintain surveil-lance of the conditions of the tubes in the event that there is evidence of mechanical damage or progressive degradation due to design, manufacturing errors, or inservice conditions that lead to corrosion. Inservice inspection of steam generator tubing also provides a means of characterizing the nature and cause of any tube degradation so that corrective measures can be taken. The plant is expected to be operated in a manner such that the secondary coolant will be maintained within those chemistry limits found to result in negligible corrosion of the steam generator tubes. If the secondary coolant chemistry is not maintained within these limits, localized corrosion may likely result in stress corrosion cracking. The extent of cracking during plant operation would be limited by the limitation of steam generator tube leakage between the Reactor Coolant System and the Secondary Coolant System (reactor-to-secondary leakage = 500 gallons per day per steam generator). Cracks having a reactor-to-secondary leakage less than this limit during operation will have an adequate margin of safety to withstand the loads imposed during normal operation and by postulated accidents. Operating plants have demonstrated that reactor-to-secondary leakage of 500 gallons per day per steam generator can readily be detected by radiation monitors of steam generator blowdown. Leakage in excess of this limit will require plant shutdown and an unscheduled inspection, during which the leaking tubes will be located and plugged. Wastage-type defects are unlikely with proper chemistry treatment of the secondary coolant. However, even if a defect should develop in service, it will be found during scheduled inservice steam generator tube examinations. Plugging will be required for all tubes with imperfections exceeding the plugging limit of 40% of the tube nominal wall thickness. Steam generator tube inspections of operating plants have demonstrated the capability to reliably detect degradation that has penetrated 20% of the original tube wall thickness. Whenever the results of any steam generator tubing inservice inspection fall into Category C-3, these results will be promptly reported to the Commission in a Special Report pursuant to Specification 6.9.2 within 30 days and prior to resumption of plant operation. Such cases will be considered by the Commission on a case-by-case basis and may result in a requirement for analysis, laboratory examinations, tests, additional eddy-current inspection, and revision of the Technical Specifications, if necessary. MILLSTONE - UNIT 3 B 314 4-3

LBDCR No. 04-1P3-015 February 24, 2005 REACTOR COOLANT SYSTEM BASES 3/4.4.6 REACTOR COOLANT SYSTEM LEAKAGE 314.4.6.1 LEAKAGE D-EECTION SYSTEMS The RCS Leakage Detection Systems required by this specification are provided to monitor and detect leakage from the reactor coolant pressure boundaxr. These Detection Systems are consistent with the recommendations of Regulatoy Guide I.A5, 'Reactor Coolant Pressure Boundary Leakage Detection Systems," May 1973. ICO)3.46.1 1.b Containment Sump Drain Level or Pumped Ca itvMonitoring Ssterm The intent of LCO 3.4.6.1.b is to have a system able to monitor and detect leakage from the reactor coolant prssurc bounda (RCPB). The system can use sump level pup capacity or both as the LCO implies. R does nothav to have two separte se sc o nment Dain Sump Level or Pumped Capacity Monitonnge, System is define as any one of the following three Systems: A. 3DAS-P1O, Unidentified Leakage Sump Pump, and associated local and main board annunciation. B. 3DAS-P10 Unidentified Leakage Sump Pump, and computer point 3DAS-L39 and CVNq 2 C. 3DAS-P2A or 3DAS-P2B, Containment Drains Sump Pump, and computer points 3DAS-122 and CVLKR2 or CVLKR31. To meet Regulatory Guide IAS recommendations, the Contaiment Drain Sump Level or Pumped Capacity Monitonng System must meet the following five criteria: I. Must monitor changes ia ump water level, changes in flow rate or changes In the operating fequpency of pumps.

2. Be able to detect an UNIDENIFIED LEAKAGE rate of I gpm in less thah one hour.

3. Remain OPERABLE followng an Operating Basis Eahquake (OBE).

4. Provide indication and alarm in the Control Room.

5. Procedures for converting iiarious indications to a common leakage equivalent must be available to the Operators.

The three Containment Drain Sump Level or Pumped Capacity Monitoring Systems identified above meet these five requirements as follows: A. 3DAS-PE 0. Unidentified Leakige Sbump Pump. and associated main board gannunciation.

1. Sump level is monitored at two locations by the sharting and stopping of 3DAS-P1O Unidentified Leakage SuIP Pump. Flow is measured as a function oi time between pump starts/stops and the known scump levels at which these occur.

MILLSTONE - UNIT 3 B 3/4 44 AmendmentNo.

LBDCR No. 04-MP3-01 5 February 24, 2005 REACTOR OOLANT SYSTEM BASES 314.4.6.1 LEAKAGE DETECTION SYSTEMS (Continued)

2. Two timer rlays in the control circuitry of 3DAS-P1O arc set to identify a I gpm leak rate within I hour.

3. This monitoig sstem is not seismic Category I, but is expected to remain OPERABLE dIiz an OBE. If the monitorinf ystem is not OPERABLE following a seismic cvent the ppropriate ACTION according to Technical Specifications will be take. This position has been reviewed by the NRC and documented as acceptable in the Safety Evaluation Report.

4. If the control circuitry of 3DAS-P1O identifies a I gpm leak rate within I hour, Liquid Radwaste Panel Annciator LWS 4-S CTMT UNIDENT LEAKAGE TR-OUIB- and Main lBoard Ain'ciator MBI B 4-3w RAD LIQUID WASTE SYS Th.OUBLE, will alaim. These contol circuits and alins operate indepndently from the plant process computer.

IfIhe com~putcr is noperable, these control circuits and alarms meet the Technical Spedficahon requirements for the Containment Drain Sump Level or Pumped Cipcit MoitoingSystem.

5. To convert the unidentified leakage sump pump run times to a leakage rate, use the following formula:

O3DAS-PIO rmn times in minutes - Lnumber of 3DAS-PIO starts xc.5 minutes) x 20 gpm Elapsed monitored Time in minutes B. 3DAS-Pi0. Unidentified Leakage Sunp Pump. and computer points 3DAS-L39 end I. Sump level is monitored by 3DAS-LB39, the Unidentified Leakage Sump Level indicator. This level indicator provides an input to computer point 3DAS-L39.

2. The plant process computer calculates a leakage rate every 30 seconds when 3DASP mindicates stop. This leaka rat is displayed via computer pot CVLKR2. When pump Pl0 does run, te leakage rat cculation is stopped and resumes 10 minues afcr pump P10 stops. If it cannot ovide a value of the leakage ate with any 54 minute interval, CVDASP1ONC LKG R1 NOT CALC) alarms wblch alerts the Operator that UNDENTIFID LEAKAGE cannot be deterind

3. This monitoing system is not seismic Category I, but is expected to remain OPERABLE dinB an OBE. If the monitoring system is not OPERABLE following a seismic event: the appropriate AMON according to Technical Specifications will be taken.

4. A priorty computeralarm (CVLKR2) is generated If the calculated leakage rate is reater than a value specified on the Priority Alarm Point Log. This alarm value

                 ~ould be set to alrtthe Opeaoto a possible RCS leakrate in exeess of the Technical Specification maximum allowed UNIDENIFIED LEAKAGE. The alarm MLLSTONE -UNIT 3                            B 314 4-4a                          AmendmentNo.

6dci o"h , I &r~-J

LBDCR No. 04-MP3-015 Febray 24,2005 REACTOR COOLANT SYSTEM BASES 314.4.6.1 LEAKAGE DETECTON SYSTEMS (Continued) value may be set at one gallon per minute or less above the rate of DENTIFIED LEAKAGE, from the reactor coolant or auxiliary systems, into the unidentified leakage sump. The rate of IDENIIFIED LEAKAGE may be determined by either measurement or analysis. If the Priority Alarm Point Log is adjusted, the high leakage rate alam will be bounded by the IDENTFIED LEAKAGE rate and the low leaage rate alarm wil be set to notify the operator that a decrease in leakage may requre the high leage rate alarm to be reset. The priority alarm setpoint shall be no greater than 2 gallons er minute. This ensures that the IDENTIFIED LEAKAGE will not maskca I mncsease in UNIDENTIIED LEAKAGE that is of concern. The 2 gallons per minute limit is also within the identified leakage sump level monitoring system alarm operating range which has a maximum setpoint of23 gallons per minute. To convert unidentified leakage sump level changes to leakage rate, use the following fomula: Note: Wait 10 minutes after 3DAS-P 10 stops before taking level readings. 1,0831Sgallons x-hchange fn level from 3DAS-L39 1% time between level readings in minutes C. 3DAS-P2A or 3DAS-P2B. Containment Drains Sump Pump. and comouter points 3DAS-L22 and CVLKR2 or CVLKR31.

1. Sump level is monitored by 3DAS-L122, the Containment Drains Sump Level Indicator. TWis level indicator provides an input to computer point 3DAS-L22.

This method can be used to monitor UNIDENTIFED LEAKAGE when Pump PlO and Its associated equipment is inoperable provided Pump P10 is out of service and 3DAS-L139 idicates that the unidentfied leakage sump is o o to the contament drains sump (appromimately 36% level an 3DAS-139). In this case, CYL and CVLKR3I monitor flow rate by co ing level ndications on the containment drains sump when Pumps P1O, P2A, P2B and P1 are not nuining.

2. The plant process computer calculates a leakage rate every 30 seconds when 3DAS-Pl0, 3DAS-PI, 3DAS-P2A and 3DAS-P2B indicate stop. This leakage rate is displayed via computer points CVLKR3I and CVLXR2 when 3DAS-P10 is off and when the unidentified leakage sump is overflowing to the containment drains sump. When one of these pumps does run, the leakage rate calculation is stopped and resumes 10 minutes after adl pumps stop. If it cannot provide a value of the leakage rate ithin. any 54 minute interval, two computer point alarms (CVDASP2NC, UNDNT LKG RT NOT CALC and CVDASP2NC, SP 3 LKG RT NT CALQ are generated which alerts the Operator that UNIDE IED LEAKAGE cannot be detemained.

MILLSTONE - UNIT 3 B 314 44b Amendment No.

                                                           ,BAS~teo~ Q         4       f    8r- c  -&) -

LBDCR No. 04-MP3-15 February 24, 2005 REACTOR COOLANT BASES 314A4.6.1 LEAKAGE DETECTION SYSTEMS (Continued)

3. This monitoring system is not seismic Category I, but is expected to remain OPERABLE during an OBE. If the monitoring system is not OPERABLE following a sesmic event, the appropriate ACTION according to Technical Specifications will be taken.

4. Two priority computer alarms (CVLKR2 and CVL 31I) are generated if the calculated leakage rate is greater than'a value specified on the Priority Alarm Point Log. lhis alarn alue should be set to alertthe Operatos to a possible RCS Icak rate in excess of the Technical Specification maximum allowed UNIDENTFIED LEAKAGE The alarm value may be set at one gallon per minute or less above the rate of DEN 1 LEAKAGE, fiom the reactor coolant or auxiliary systems, into the containment drains sump. The rate of IDENTIFID LEAKAGE may be determined by either measurement or by analysis. If the Priority Alarm Point Log is adjusted, the high leakeage iate alarm will be bounded by the IDENTF I LEAKAGE rate and the low leakage rate alarm will be set to notify the operator that a decrease in leakage may require the high leakagt rate alarm to be reset. lbe priority alarm setpoint shall be no greater than 2 gallons per minute. This ensures that the IDENTIFIED LEAKAGE will not mask a small increase in UNIDENTIFIED LEAKAGE that is of concern. The 2 gallons per minute limit is also within the containment drains sump level monitoring system alarm operating range which has a maximum setpoint of 2.5 gallons per minute.

5. To convert containment drains sump rnm times to a leakage rate, refer to procedure SP3670.l for guidance on the conversion method.

314.A.6.2 OPERATIONAL LEAKAGE PRESSURE BOUNDARY LEAKAGE of any magnitude is unacceptable since it may be indicative of an impending gross failur of the pressure boundary. Therefore, the presence of any PRESSURE BOUNDARY LEAKAGE requires the unit to be promptly placed in COLD SHUTDOWN. Industry experience has shown that while a limited amount of leakage is expected from the RCS, the unidentified portion of this leakage can be reduced to a threshold value ofless than 1 gpm. This thshold value is sufficiently low to ensure early detection of additional leakage. The total steam generator tube leakage limit of I gpm for all steam generators not isolated from the RCS ensures that the dosage contribution from the tube leakage will be limited to a small fraction of 10 CFER Part 100 dose guideline values in the event of either a steam generator tube rupture or steam line break. The I gpm limIt is consistent with the assumptions used in the analysis of these accidents. The 500 gpd leakage limit per steam generator ensures that steam generator tube integrity is maintained in the event of a main steam line rupture or under LOCA conditions. MILLSTONE - UNIT 3 B 3/4 44c AmendmentNo. 6a9o00 (r e91f4& t-./

                                                                                                   - c

LBDCR No. 04-MP3-015 Febrary 24, 2005 REACTOR COOLANT SYSTEM BASES 314.4.6.2 OPERATIONAL LEAKAGE (Continued) The 10 gpm IDENTIFID LEAKAGE limitation provides allowance fora limited amount of leakage from known sources whose presence will not interfere with the detection of UNIDENTIFID LEAKAGE by the Leakage Detection Systems. The CONIROLLED LEAKAGE limitation restricts operation when the total flow supplied to the reactor coolant pump seals exceeds 40 gpm with the modulating valve in the supply line fully open at a nominal RCS pressure of2250 psia. This limitation ensures that in the event of a LOCA, the safety injection flow will not be less than assumed in the safety analysts. A Limit of`40 gpm is placed on CONROLLED LEAKAGE. CONTROLLED LEAKAGE is determined under a set of reforence conditions, listed below:

a. One Charging Pump in operation.

b. RCS pressure at 2250 +/- 20 psia.

By limiting CON IROLUD LEAKAGE to 40 gpm during normal operation, we can be l assured that during an SI with only one charging punp injecting, RCP seal injection flow will continue to remain less than 80 gpm as assumed in accident analysis. When the seal injection throttle valves are set with a normal charging line up, the throttle valve position bounds conditions where higher charg header pressures could exist. Therefore, conditions which create higher charging header pressures such as an isolated chargng line, or two pumps in service are bounded by the single pump-normal system lineu surveillance configuration. Basic accident analysis assumptions are that 80 gpm flow Is provided to the seals by a single pump In a nmout condition. The specified allowable leakage from any RCS pressure isolation valve is sufficiently low to ensur early detection of possible In-series valve failure. t is apparent that when pressure isolation Is provided by two in-series valves and when failure of one valve in the pair can go undetected for a substantial length of time, verification ofvalve integrity is required. Since these valves are important inpreventing ovep ation d rupture of the ECCS low pressure piping which could result in a LOCA, these valves should be tested periodically to ensure low probability of gross failure. Steady state operation is required to peform a proper inventory balance since calculations during maneuvering ar not useful. For RCS Operational Leakage determination by water inventory balance, steady state is defined as stable RCS pressure, temperatuire, power level, pressurizer and makeup tank levels, makeup and letdown, and reactor coolant pump seal injection and return flows. The Surveillance Requirents for RCS pressure isolation valves provide assurance of valve integrity thereby reducing the probability of gross valve failure and consequent interaystem LOCA. Leakage from the RCS pressure isolation valve is IDENTIFED LEAKAGE and will be considered as a portion of the allowed limit MILLSTONE - UNIT 3 B 314 4-4d Amendment No. M, 7b~ M aStt 85-qrE

REACTOR COOLANT SYSTEM BASES 3/4.4.6.2 OPERATIONAL LEAKAGE (Continued) Entry into MODES 3 and 4 is allowed to establish the necessary differential pressures and stable conditions for performance of Surveillance Requirement 4.4.6.2.2 (including Surveillance Requirement 4.4.6.2.2.d) for RCS pressure isolation valves which can only be leak-tested at elevated RCS pressures. The requirements of Surveillance Requirement 4.4.6.2.2.d to verify that a pressure isolation valve is OPERABLE shall be performed within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> after the required RCS pressure has been met. In MODES 1 and 2, the plant is at normal operating pressure and Surveillance Requirement 4.4.6.2.2.d shall be performed within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> of valve actuation due to automatic or manual action or flow through the valve. In MODES 3 and 4, Surveillance Requirement 4.4.6.2.2.d shall be performed within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> of valve actuation due to automatic or manual action or flow through the valve if and when RCS pressure is sufficiently high for performance of this surveillance.

References:

1. Letter FSD/SS-NEU-3713, dated March 25, 1985.

2. Letter NEU-89-639, dated December 4, 1989.

MILLSTONE - UNIT 3 B 3/4 4-4e Amendment No. 209 0926 AUG 2 1 2M2

REACTOR COOLANT SYSTEM BASES OPERATIONAL LEAKAGE (Continued) The specified allowable leakage from any RCS pressure isolation valve is sufficiently low to ensure early detection of possible In-series valve failure. It is apparent that when pressure isolation is provided by two in-series valves and when failure of one valve in the pair can go undetected for a substantial length of time, verification of valve integrity is required. Since these valves are important in preventing overpressurization and rupture of the ECCS low pressure piping which could result in a LOCA, these valves should be tested periodically to ensure low probability of gross failure. The Surveillance Requirements for RCS pressure isolation valves provide assurance of valve integrity thereby reducing the probability of gross valve failure and consequent intersystem LOCA. Leakage from the RCS pressure isolation valve is IDENTIFIED LEAKAGE and will be considered as a portion of the allowed limit. 3/4.4.7 DELETED I 3/4.4.8 SPECIFIC ACTIVITY The limitations on the specific activity of the reactor coolant ensure that the resulting 2-hour doses at the SITE BOUNDARY will not exceed an appropriately small fraction of 10 CFR Part 100 dose guideline values following a steam generator tube rupture accident in conjunction with an assumed steady-state reactor-to-secondary steam generator leakage rate of 1 gpm. The values MILLSTONE - UNIT 3 B 3/4 4-5 Amendment No. 204 I 0792

LBDCR No. 04-MP3-009 December 9,2004 REACTOR COOLANT SYS BASES EPEf C ACllVITY (Continued) for the limits on specific activity represent limits based upon a parametric evaluation by the NRC oftypical site locations. These values are conservative in that specific site parameters of the Millstone site, such as SITE BOUNDARY location and meteorological conditions, were not considered in this evaluation. The ACTION statement permitting POWER OPERATION to continue for limited time periods with the reactor coolant's specific activlty greater than I microCurie/gram DOSE EQUIVALENT 1-13 1,but within the allowable limit shown on Figure 3.4-1, accommodates possible iodine spildng phenomenon which may occur folowing changes in THERMAL POWER. The sample analysis for determining the gross specific activity and E can exclude the radiolodines because of the low reactor coolait limit of I microCurielgram DOSE EQUIVALENTII-131, and because, if the limit Is exceeded, the radfiodine level is to be determined every 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />. If the gross specific activity level and radioiodine level in the reactor coolant were at their limits, the radioiodine contribution would be approximately 1%. In a release of reactor coolant with a typical mixture of radioactivity, the actual radioiodine contribution would probably be about 20%. The exclusion of radionuclides with half-lives less than 10 minutes from these determinations has been made for several reasons. The first consideration is the difficulty to identify,short-lived radionuclides in a sample that requires a significant time to collect, transport, and anlyze. The second consideration is the predictable delay time between the postulated release of radioactivity from the reactor coolant to its release to the environment and transport to the SITE BOUNDARY, which is relatable to at least 30 minutes decay time, The 6boice of 10 minutes for the half-life cutoffwas made because of the nuclear characteristics ofthe typical reactor coolant radioactivity. The radionuclides in the typical reactor coolant have half-lives of less than 4 minutes or half-lives of greater than 14 minutes, which allows a distinction between the radionuclides above and below a half-life of 10 minutes. For these reasons the radionuclides that are excluded firom considejation are expected to decay to very low levels before they could be transported from the reactor coolant to the SITE BOUNDARY under any accident condition. MILLSTONE- UNIT 3 B 314 4-6 Amendment No. bmX 1l6i&

                                                                                      ~       ~     ~ C M5bS

REACTOR COOLANT SYSTEM BASES SPECIFIC ACTIVITY (Continued) Based upon the above considerations for excluding certain radionuclides from the sample analysis, the allowable time of 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> between sample taking and completing the initial analysis is based upon a typical time necessary to perform the sampling, transport the sample, and perform the analysis of about 90 minutes. After 90 minutes, the gross count should be made in a reproducible geometry of sample and counter having reproducible beta or gamma self-shielding properties. The counter should be reset to a reproducible efficiency versus energy. It is not necessary to identify specific nuclides. The radiochemical determination of nuclides should be based on multiple counting of the sample within typical counting basis following sampling of less than 1 hour, about 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br />, about 1 day, about 1 week, and about l month. Reducing T,,, to less than 500OF prevents the release of activity should a steam generator tube rupture since the saturation pressure of the reactor coolant is below the lift pressure of the atmospheric steam relief valves. The Surveillance Requirements provide adequate assurance that excessive specific activity levels in the reactor coolant will be detected in sufficient time to take corrective action. A reduction in frequency of isotopic analyses following power changes may be permissible if justified by the data obtained. 3/4.4.9 PRESSURE/TEMPERATURE LIMITS REACTOR COOLANT SYSTEM (EXCEPT THE PRESSURIZER) BACKGROUND All components of the RCS are designed to withstand effects of cyclic loads due to system pressure and temperature changes. These loads are introduced by startup (heatup) and shutdown (cooldown) operations, power transients, and reactor trips. This LCO limits the pressure and temperature changes during RCS heatup and cooldown, within the design assumptions and the stress limits for cyclic operation. Figures 3.4-2 and 3.4-3 contain P/T limit curves for heatup, cooldown, inservice leak and hydrostatic (ISLH) testing, and data for the maximum rate of change of reactor coolant temperature. Each P/T limit curve defines an acceptable region for normal operation. The usual use of the curves is operational requirements during heatup or cooldown maneuvering, when pressure and temperature indications are monitored and compared to the applicable curve to determine that operation is within the allowable region. A heatup or cooldown is defined as a temperature increase or decrease of greater than or equal to 1OaF in any one hour period. This definition of heatup and cooldown is based upon the ASME definition of isothermal conditions described in ASME, Section XI, Appendix E. MILLSTONE - UNIT 3 B 3/4 4-7 Amendment No. by7, 197 0784

LBDCR 3-403 May 20,2004 REACTOR COOLANT SYSTEM BASES PRESSURMl~E PERAT LRE MITS (contnued) Steady state thermal conditions exist when temperature increases or decreases are <100 F in any one hour period and when the plant is not performing a planned heatup or cooldown in accordance with a procedure. The LCO establishes operating limits that provide a margin to brittle failure, applicable to the ferritic material of the reactor coolant pressure boundary (RCPB). The vessel is the component most subject to brittle failure, and the LCO limits apply mainly to the vessel. The limits do not apply to the Pressurie. The PIr limits have been established for the ferritic materials of the RCS considering ASME Boiler and Pressure Vessel Code Section XI, Appendix G (Reference 1) as modified by ASME Code Case N.640 (Reference 2), and the additional rcquirements of 10 CFR 50 Appendix 0 (Reference 3). Implementation ofthe specific requirements provide adequate margin to brittle fracture of ferritic materials during normal operation, anticipated operational occurrences, and system leak and hydrostatic tests. The neutron embrittlement effect on the material toughness is reflected by increasing the nil ductility reference temperature (RTIW) as exposure to neutron fluence increases. The actual shift in the RT1W of the vessel material will be established periodically by removing and evaluating the irradiated reacto'r vessel material specimens, in accordance with ASTM E 185 (Ref. 4) and Appendix H of 10 CFR 50 (Ref. 5). The operating P/T limit curves will be adjusted, as necessazy based on the evaluation findings and the recomendations of Regulatory Guide 1.99 (Ref. 6). The PIT limit curves are composite curves established by superimposing limits derived from stress analyses of those portions of the reactor vessel and head that are the most restrictive. At any specific pressure, temperatu, and temperature rate of change, one location within the reactor vessel will dictate the most restrictive limit. Across the span ofthe PIT limit curves, different locations may be more restrictive, and thus, the curves are composites of the most restrictive regions. The heatup curve represents a different set ofrestrictions than the cooldown curve because the directions of the thermal gradients trgh the vessel wall are reversed. The thermal gradient reversal alters the location ofthe tensile stress between the outer and inner walls. The P/T limits include uncertainty margins to ensure that the calculated limits are not inadvertently exceeded. These margins Include gauge and system loop uncertainties, elevation differences, containment pressure conditions and system pressure drops between the beltline region of the vessel and the pressure gauge or relief valve location. MILLSTONE - UNIT 3 B 314 4-8 Amendment No. 49, sS,

                                                           @('oeo        Q/   &a             y   c2*j -

REACTOR COOLANT SYSTEM BASES PRESSURE/TEMPERATURE LIMITS (continued) The criticality limit curve includes the Reference I requirement that it be

> 40F above the heatup curve or the cooldown curve, and not less than 160F above the minimum permissible temperature for ISLH testing. This limit provides the required margin relative to brittle fracture. However, the criticality curve is not operationally limiting; a more restrictive limit exists in LCO 3.1.1.4, "Minimum Temperature for Criticality."

The consequence of violating the LCO limits is that the RCS has been operated under conditions that can result in brittle failure of the ferritic RCPB I materials, possibly leading to a nonisolable leak or loss of coolant accident. In the event these limits are exceeded, an evaluation must be performed to determine the effect on the structural integrity of the RCPB components. The ASME Code, Section XI, Appendix E (Ref. 7) provides a recommended methodology for evaluating an operating event that causes an excursion outside the limits. APPLICABLE SAFETY ANALYSIS The P/T limits are not derived from Design Basis Accident (DBA) analyses. They are prescribed during normal operation to avoid encountering pressure, temperature, and temperature rate of change conditions that might cause undetected flaws to propagate and cause nonductile failure of the RCPB, an unanalyzed condition. Reference 1, as modified by Reference 2, combined with thel additional requirements of Reference 3 provide the methodology for determining I the P/T limits. Although the P/T limits are not derived from any DBA, the P/T limits are acceptance limits since they preclude operation in an unanalyzed condition. RCS P/T limits satisfy Criterion 2 of 10CFR50.36(c)(2)(ii). LCO The LCO limits apply to the ferritic components of the RCS, except the Pressurizer. These limits define allowable operating regions while providing margin against nonductile failure for the controlling ferritic component. The limitations imposed on the rate of change of temperature have been established to ensure consistency with the resultant heatup, cooldown, and ISLH testing P/T limit curves. These limits control the thermal gradients (stresses) within the reactor vessel beltline (the limiting component). Note that while these limits are to provide protection to ferritic components within the reactor coolant pressure boundary, a limit of 100F/hr applies to the reactor coolant pressure boundary (except the pressurizer) to ensure that operation is maintained within the ASME Section III design loadings, stresses, and fatigue analyses for heatup and cooldown. MILLSTONE - UNIT 3 B 3/4 4-9 Amendment No. OF7, 197 0781

S . I S BDCPR 04-MP3401

                           ,ECROTATYTR BASES3                                                                          .         .

Violafiog the W tplttcMSebfsi~d of ieE bo~s of le OffIysesinacan

• icrcassthsses niother PB c eniL'e Ibe iences d6pchd onsev~fifltor~s, is follows:

Lv

• hsouvetity difeddo m'th6 dllotvablb praig WI'rie orth-

                   ..        ~~~              af$RA9Me~II                    i14.....*.

th*

• ii bf thne thoL8.:'
• vlolatedw.o** vi*j alfo*1ihe t ..- . *l irdseIs albs to bwme -.

c Te cxisteus, sd,16d orint6Mlohs of fi inth6 vessel uiateria The - ardowiqf apte6ntiwm . ps if oii Spbg -ak 1' difie p, b~raod Se.i~'d re*nts0X, O, re.)h

• h£l Pthe
• liit4foetopXjdo :fs.#r opqeat ii. ; rciaorvi~oDBS 3, 4, anfd 5o¶ n I.eepindit Coneehfonio leJlihi. The limits do not During MObES I and 2, odherTechnIcal Specdfications pvde for pvrttiqn tha;tcan be nore restrictive than or can upplementidwPlT limits. LCO 32;S, ' DMB maetre%,LCO

 *3.23.1, "RCS Flow Rate and Nuclear Enapy Rise Hot Channel Facto?'; LCO 3.1.4, nIzimum Ttmaperature for Cdticali; and Safty Limit 2.1, "'Safety{mIts, also provide operational restrictions forpressure.m mpeabtue=pnd                                       mum pr~swe. Furtbermxc, MODESgiffind 24ire qt-.ov:ofhoencer                                                      fr n-Antslcess and'elve-heen                F&Uredfb ZIPi1.'.*oesscl amtscs~oeenp~fnnd~o           n ianieuirerig pro$1csI                                 po~s~scnuic n or:

descedit.

 **CtN                *...

• J.. ..

outsldei&e~r .i i~it~st .. corrctc usothat lhte RCPB i eto.ta~ot dilonjthat sbeen vcifibystrness a~ses. .he Alowd Outage tunes (AOT-s rflects lf iegencyof restoning die pametersno.'itlh the ahtlj-zdr Most violations .wil nbt be severe and the acity & obeisiE4jn s tine Iaco ed mir. Besides restoring operation within lnts an evatuationis requird to deterinine IfRCS operation can continue. The evaluation must veft the RCFB Integrity remains acceptable and must be completed before continuing operation. Several methods may be used, including comparison with pre-analyzed fransients In the stress analyses, new analyses, or inspection of the components. mllSO1TE -UNrT2 B 314 410 Amendment lo. 4 4, 2W.

                                               *                                       $atsb         1&ffiy-              -Y-25-6

LBDCR No. 04-M3-015 Febrary 24, 2005 REACTOR COOLANT SYSTEM BASES pRESSUR~fBM lllRAT LlbI1S Legqnuuc ASME Codc, Section XI, Appendi7E-RE 7), maybe used to support the evaluation. However, Its use is restricted to evaluation of the vessel beldine. The 72 hour AOT when operating in MODES I through 4 is reasonable to accomplish the evaluation. The evaluation for a mild violaiion is possible within this time, but more severe violations may require special, event specific stress analyses or inspections. A favorable evaluation must be completed before continuing to operate. This evaluation must be completed whenever a limit is exceeded. Restoration within the AOT alone is insufficient because higher than analyzed stresses maylhave occurred and may have affected the RCPB integrity. Ifthe required remedial actions are not conpleted within the allowed tines, the plant must be placed in a lower MODE or not allowed to enter MODE 4 because either the RCS remained in an unacceptable Ptr region for an extended period of increased stress or a sufficiently severe event caused entry into an unacceptable region. -Eitherpossibility indicates a need for more carefid exanation of the event, best accomplished with the RCS at reduced pressure and temperature. In reduced pressure and temperature conditions, the possibility ofpropagation with undetected flaws is decreased. If the required evalhation for continued operation inMODES I through 4 cannot be accompliihed within 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> or the results are inaeteite or unfavorable, action must proceed to reduce pressure and temperature as specified in the ACT10N statement A favorable evaluation must be completed and docunented before returning to operating pressure and temperature conditions. Pressure and temperature are reduced by bringing the plant to MODE 3 within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and to MODE Swith RCS pressure < 500 psia within the next 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />. Completion ofthe required evaluation following limit violation in other than MODES I through 4 is required before plant startup to MODE 4 can proceed. The AOIs are reasonable, based on operatg experience to reach the required plant conditions from full power conditions inan orderly manner and without challenging plant systems. SURVERLANCE RELUR Verification that operation is within the LCO limits as well as the limits of Figures 3.4-2 and 3A-3 is required every 30 minutes when RCS pressure and temperature conditions are undergoing planned changes. This frequency Isconsidered reasonable Inview of the control room indication available to monitor RCS status. MILSTONE -UNIT 3 B 314 4-11 Amendment No. 49, @9, 4*, 4, P9 6,8V CVq wto 6 3-,95 &-L5

LBDCRNo. 044M3-015 February 24,2005 REACIOR COOLANT SYSTEM BASES PRESSUREtlEMPERATURE LMITS (continued) Surveillance for heatup, cooldown, or ISLH tesig may be discontinued when the definition given in the relevant plant procedure for ending the activity is satisfied. This Surveillance Requirement is only required to be performed during system heatup, cooldown, and ISLH testing. No Surveillance Requirement is given for criticality operations because LCO 3.1.1.4 contains a more restrictive requiremente It is not necessary to perform Surveillance Requirement 4.4.9.1.1 to verify compliance with Figures 3.4-2 and 3.4-3 when the reactor vessel is filly detensioned. During REFUELING with the head fiuy detensioned or off the reactor vessel, the RCS is not capable of being pressurized to any significant value, The limiting thermal stresses which could be encountered during this time would be limited to flood-op using RWST water as low as 40°F. It is not possible to cause crack growth ofpostulated flaws in the reactor vessel at normal REFUELING temperatures even injecting40FWater.

1. ASME Boiler and Pressure Vessel Code, Section X, Appendix Q "Fracture Toughness for Protection Against Failure," 1995 Edition.

2. ASME Section XI, Code Case N-640, "Alternative Reference Fracture Toughness for Development ofP-T Limit Curves," dated February 26, 1999.

3. 10 CFR 50 Appendix G."Fracture Toughness Requirements."

4. ASTM E 185482, 'Standard Practice for Conducting Surveillance Tests for Light-Water Cooled Nuclear Power Reactor Vessels, E 706."

5. 10 CFR SO Appendix H Reactor Vessel Material Surveillance Program Requirements."

6. Regulatory Guide 1.99 Revision 2, 'Radiation Embrittlement of Reactor Vessel Materials," dated May 1988.

7. ASME Boiler and Pressure Vessel Code, Section XI, Appendix E, "Evaluation of Unanticipated Operating Events," 1995 Edition.

MILLSTONE - UNIT 3 B 3/4 4-12 Amendment No. 48, 44 497, 204,

                                                                                              -24, f360&             (3Ut7W       CZ ?6, )5

This page intentionally left blank MILLSTONE - UNIT 3 B 3/4 4-13 Amendment No. fY, Y97, 204 0793

This page intentionally left blank MILLSTONE - UNIT 3 B 3/4 4-14 Amendment No. f#, FF, Ak7, 204 0793

REACTOR COOLANT SYSTEM BASES I OVERPRESSURE PROTECTION SYSTEMS BACKGROUND The Cold Overpressure Protection System limits RCS pressure at low temperatures so the integrity of the reactor coolant pressure boundary (RCPB) is not compromised by violating the isothermal beltline pressure and temperature (P/T) limits developed using the guidance of ASME Section XI, Appendix G (Reference 1) as modified by ASME Code Case N-640 (Reference 2). The reactor vessel is the limiting RCPB component for demonstrating such protection. Cold Overpressure Protection consists of two PORVs with nominal lift setting as specified in Figures 3.4-4a and 3.4-4b, or two residual heat removal (RHR) suction relief valves, or one PORV and one RHR suction relief valve, or a depressurized RCS and an RCS vent of sufficient size. Two relief valves are required for redundancy. One relief valve has adequate relieving capability to prevent overpressurization of the RCS for the required mass input capability. MILLSTONE - UNIT 3 B 3/4 4-15 Amendment No. ff, 99, J79, 197, 0902 7f7, 204 I

LBDCR No. 04-MP3-015 Febnuaiy 24,2005 REACTOR COOLANT SYSTEM BASES QVER PEESSU R ROTECIIO N S YSTEMIS ( on inued The use of a POV for Cold Overpressure Protection is limited to those conditions when no more than one RCS loop is isolated from the reactor vessel. When two or more loops are isolated, Cold Overpressure Protection must be provided by either (he two RHR suction relief valves or a depressrized and vented RCS. The reactor vessel material is less tough at low temperatures than at normal operating temperature. As the vessel neutron exposure accumulates, the material toughness decreases and becomes less resistant to stress at low temperatures (Ref 3). RCS pressure, therefore, is maintained low at low temperatures and IsIncreased only as temperature Is increased. The potential for vessel overpressurization is most acute when the RCS is water solid, occurring wile shutdown; a pressure fluctuation can occur more quickly than an operator can react to relieve the condition. Exceeding the RCS PIt limits by a significant amount could cause nonductile cracking of the reactor vessel. LCO 3.49.1, "Pressure/Temperature Limits - Reactor Coolant System," requires administrative control of`RCS pressure and temperature during heatup and cooldown to prevent exceeding the limits provided in Figures 3A-2 and 3.4-3. This LCO provides RCS overpressure protection by limiting mass input capability and requiring adequate pressure relief capacity. Limiting mass input capability requires Oll Safety Injection (SIM pumps and all but one centrifugal charging pump to be incapable of injection into the RCS. The pressure relief capacity requires either two redundant relief valves or a depressurized RCS and an RCS vent of sufficient size. One relief valve or the open RCS vent is the overpressure protection device that acts to terminate an increasing pressure event. Wit minimum mass input capability, the ability to provide core coolant addition is restricted. The LCO does not require the makeup control system deactivated or the safety injection (SI) actuation circuits blocked. Due to the lower pressures inthe Cold Overpressure Protection modes and the expected core decay heat levels, the mkeup system can provide adequate flow via the makeup control valve. If a loss of RCS inventory or reduction in SHUTDOWN MARGIN event occurs, the appropriate response nill be to correct the situationby starting RCS makeup pumps. If the loss of inventory or SHUTDOWN MARGIN is significant, this may necessitate the use of additional RCS makceup pumps that are being maintained not capable of injecting into the RCS in accordance with Technical Specification 3.4.93. The use of these additional pumps to restore RCS inventory or SHUTDOWN MARGIN will require entry Into the associated ACTION statement The ACTION statement requires Immediate action to comply with the specification. The restoration of RCS inventory or SHUTDOWN MARGIN can be considered to be part of the immediate action to restore the additional RCS makeu pumps to a not capable of injecting status. While recovering RCS inventory or SHUTDOWN MARGIN, RCS pressure will be maintained below the PIT limits. After RCS inventory or SHUTDOWN MARGIN has been restored, the additional pumps should be immediately made not capable of injecting and the ACTION statement exited. MILLSTONE -UNIT 3 B 3/4 4-16 Amendment No. 49,8848,4,45,49, fbaqo/

REACTOR COOLANT SYSTEM BASES OVERPRESSURE PROTECTION SYSTEMS (continued) PORV Reuuirements As designed, the PORV Cold Overpressure Protection (COPPS) is signaled to open if the RCS pressure approaches a limit determined by the COPPS actuation logic. The COPPS actuation logic monitors both RCS temperature and RCS pressure and determines when the nominal setpoint of Figure 3.4-4a or Figure 3.4-4b is approached. The wide range RCS temperature indications are auctioneered to select the lowest temperature signal. The lowest temperature signal is processed through a function generator that calculates a pressure setpoint for that temperature. The calculated pressure setpoint is then compared with RCS pressure measured by a wide range pressure channel. If the measured pressure meets or exceeds the calculated value, a PORV I is signaled to open. The use of the PORVs is restricted to three and four RCS loops unisolated: for a loop to be considered isolated, both RCS loop stop valves must be closed. If more than one loop is isolated, then the PORVs must have their block valves closed or COPPS must be blocked. For these cases, Cold Overpressure Protection must be provided by either the two RHR suction relief valves or a depressurized RCS and an RCS vent. This is necessary because the PORV mass and heat injection transients have only been analyzed for a maximum of one loop isolated, the use of the PORVs is restricted to three and four RCS loops unisolated. The RHR suction relief valves have been qualified for all mass injection transients for any combination of isolated loops. In addition, the heat injection transients not prohibited by the Technical Specifications have also been considered in the qualification of the RHR suction relief valves. Figure 3.4-4a and Figure 3.4-4b present the PORV setpoints for COPPS. The setpoints are staggered so only one valve opens during a low temperature I overpressure transient. Setting both valves to the values of Figure 3.4-4a and Figure 3.4-4b within the tolerance allowed for the calibration accuracy, ensures that the isothermal P/T limits will not be exceeded for the analyzed isothermal events. When a PORV is opened, the release of coolant will cause the pressure increase to slow and reverse. As the PORV releases coolant, the RCS pressure decreases until a reset pressure is reached and the valve is signaled to close. The pressure continues to decrease below the reset pressure as the valve closes. MILLSTONE - UNIT 3 0782 B 3/4 4-16a Amendment No. f?, F?, F7d197

REACTOR COOLANT SYSTEM BASES OVERPRESSURE PROTECTION SYSTEMS RHR Suction Relief Valve Requirements The isolation valves between the RCS and the RHR suction relief valves must be open to make the RHR suction relief valves OPERABLE for RCS overpressure mitigation. The RHR suction relief valves are spring loaded, bellows type water relief valves with setpoint tolerances and accumulation limits established by Section III of the American Society of Mechanical Engineers (ASME) Code (Ref. 4) for Class 2 relief valves. When the RHR system is operated for decay heat removal or low pressure letdown control, the isolation valves between the RCS and the RHR suction relief valves are open, and the RHR suction relief valves are exposed to the RCS and are able to relieve pressure transients in the RCS. RCS Vent Reguirements Once the RCS is depressurized, a vent exposed to the containment atmosphere will maintain the RCS at acceptable pressure levels in an RCS overpressure transient, if the relieving requirements of the transient do not exceed the capabilities of the vent. Thus, the vent path must be capable of relieving the flow resulting from the limiting mass or heat input transient, and maintaining pressure below the P/T limits for the analyzed isothermal events. For an RCS vent to meet the flow capacity requirement, it requires removing a Pressurizer safety valve, removing a Pressurizer manway, or similarly establishing a vent by opening an RCS vent valve provided that the opening meets the relieving capacity requirements. The vent path must be above the level of reactor coolant, so as not to drain the RCS when open. MILLSTONE - UNIT 3 B 3/4 4-17 Amendment No. gy7, 197 0782

LBDCR No. 04-MP3-015 February 24,2005 REACTOR COOLANT SYSIEM BASES OVERPRESSURE PROTECITON SYSTEMS Lcontinued APPLICABLE SAFETY ANALYSIS Safety analyses (Ref. 5) demonstrate that the reactor vessel is adequately protected against exceeding the P/T limits for the analyzed isothermal events. In MODES 1, 2, AND 3, and in MODE 4, with RCS cold leg temperature iceeding 226°F, hepressurizer safety valves will provide RCS overpressure protection In the ductile region. At 226°F and below, overpressure prevention is proved by two means: (1) two OPERABLE relief valves, or (2) a depressurized RCS with a sufficiently sized RCS vent, consistent with ASME Section XIL Appendix G for temperatures Iess than RlwjT + 50F. Each of these means has a limited overpressure relief capability. The required RCS temperatre for a given pressure increases as the reactor vessel material toughness decreases due to neutron embrittement. Each time the Technical Specification curves. are revised, the cold overrssre protection must b re-evaluated to ensure its functional requirements continue to be met using the RCS relief valve method or the depressurized and vented RCS condition. Transients capable of overpressurizing the RCS are categorized as either mass or heat input transients, exanples of which follow-. Mass Input Transients

a. Inadvertent safety injection; or

b. Charginglletdown flow mismatch Heat In Transicnts

a. Inadvertent actuation ofPressuriZer heaters;

b. Loss of RHR cooling; or

c. Reactor coolant pump (RCP) startup with temperature asymmetry within the RCS or between the RCS and steam generators.

The lchnical Specifications ensure that mass input transients beyond the OPERABIlLTY of the cod o erpse protection means do not occur by rendering all Safety Injection Pumps and all but oe centrifugal charging pump incapable ofi jecting into the RCS whenever an RCS cold leg is S226°F. The Technical Specifications ensure that energy addition transients beyond the OPERABIITY of the cold overpressure protection means do not occur by limiting reactor coolant pump starts. LCO 3.4.1A.1, "Reactor Coolant Loops and Coolant Circulation - COLD SHUTDOWN - Loops Filled," LCO 3.4.A2, "Reactor Coolant MILLSTONE - UNIT 3 B 314 4-18 Amendment No. 47 49, lcic-& O/iwrX f, &

                                                                          *LBDCRNo. 04-MP3-015 February 24, 2005 REACTOR COOLAN SYSTEM BASES OVERPRURSURE PROTEC17ON SYSTEMS &motinum Loops and Coolant Circulation - COLD SHUTDOWN - Loops Not Filled," and LCO 3.4.1.3,

'MReactor Coolant Loops and Coolant Circulation - HOT SHUTDOWN" limit starting the first reactor coolant pump such that it shall not be started when any RCS loop wide range cold leg temperature is S 226°F unless the secondary side water temperature of each steam generator is <50'F above each RCS cold leg temperature. The restrictions ensure the potential energy addition to the RCS from the secondary side of the steam generators will not result in an RCS overpressurization event beyond the capability ofthe COPPS to mitigate. Ihe COPPS utilizes the pressunzerPORVs and the REIR relief valves to mitigate the limiting mass and energy addition events, thereby protecting the Isothermal reactor vessel beldine PJI limits. The restrictions will ensure the reactor vessel will be protected from a cold overpressure event when gtart the first RCR If at least one RCP is operating, no restrictions ae necessary to start additional RCPs for reactor vessel protection. In addition, this restriction only applies to RCS loops and associated components that are not isolated firom the reactor vessel. The RCP starting criteria are based on the equipment used to provide cold overpressure protection. A maximum temperature differential of 50F between the steam generator secondary sides and RCS cold legs will limit the potential energy addition to within the capability of the pressurizer PORVs to mitigate the transient. The RHR relief valve are also adequate to mitigate energy addition transients constrained by this temperature differential limit, provided all RCS cold leg temperatu are at or below 150°F. The ability of the RHR relief valves to mitigate energy addition transients when RCS cold leg temperature is above 150°F has not been analyzed. As a result, the temperaure of the steam generator secondary sides must be at or below the RCS cold leg temperature if the RHR relief valves are providing cold overpressure protection and the RCS cold leg temperature is above 1500F. MLLSTONE - UNIT 3 B 3/4 4-19 Amendment No. 45,49,

                                                         ]B3ve                aqiy--     Ls-S

REACTOR COOLANT SYSTEM BASES OVERPRESSURE PROTECTION SYSTEMS (continued) The cold overpressure transient analyses demonstrate that either one relief valve or the depressurized RCS and RCS vent can maintain RCS pressure below limits when RCS letdown is isolated and only one centrifugal charging pump is operating. Thus, the LCO allows only one centrifugal charging pump capable of injecting when cold overpressure protection is required. The cold overpressure protection enabling temperature is conservatively established at a value < 226'F based on the criteria provided by ASME Section XI, Appendix G. PORV Performance The analyses show that the vessel is protected against non-ductile failure when the PORVs are set to open at the values shown in Figures 3.4-4a and 3.4-4b within the tolerance allowed for the calibration accuracy. The curves are derived by analyses for both three and four RCS loops unisolated that model the performance of the PORV cold overpressure protection system (COPPS), assuming the limiting mass and heat transients of one centrifugal charging pump injecting into the RCS, or the energy addition as a result of starting an RCP with temperature asymmetry between the RCS and the steam generators. These analyses consider pressure overshoot beyond the PORV opening setpoint resulting from signal processing and valve stroke times. The PORV setpoints in Figures 3.4-4a and 3.4-4b will be updated when the P/T limits conflict with the cold overpressure analysis limits. The P/T limits are periodically modified as the reactor vessel material toughness decreases due to neutron embrittlement. Revised limits are determined using neutron fluence projections and the results of testing of the reactor vessel material irradiation surveillance specimens. The Bases for LCO 3.4.9.1, "Pressure/Temperature Limits - Reactor Coolant System (Except the Pressurizer)," discuss these evaluations. The PORVs are considered active components. Thus, the failure of one PORV is assumed to represent the worst case, single active failure. RHR Suction Relief Valve Performance The RHR suction relief valves do not have variable pressure and temperature lift setpoints as do the PORVs. Analyses show that one RHR suction relief valve with a setpoint at or between 426.8 psig and 453.2 psig will pass flow greater than that required for the limiting cold overpressure transient while maintaining RCS pressure less than the isothermal P/T limit curve. Assuming maximum relief flow requirements during the limiting cold overpressure event, an RHR suction relief valve will maintain RCS pressure to < 110% of the nominal lift setpoint. Although each RHR suction relief valve is a passive spring loaded device, which meets single failure criteria, its location within the RHR System precludes meeting single failure criteria when spurious RHR suction isolation valve or RHR suction valve closure is postulated. Thus the loss of an RHR suction relief MILLSTONE - UNIT 3 D 3/4 4-20 Amendment No. F7, 197 0782

REACTOR COOLANT SYSTEM BASES OVERPRESSURE PROTECTION SYSTEMS (continued) valve is the worst case single failure. Also, as the RCS P/T limits are revised to reflect change in toughness in the reactor vessel materials, the RHR suction relief valve's analyses must be re-evaluated to ensure continued accommodation of the design bases cold overpressure transients. RCS Vent Performance With the RCS depressurized, analyses show a vent size of > 2.0 square inches is capable of mitigating the limiting cold overpressure transient. The capacity of this vent size is greater than the flow of the limiting transient, while maintaining RCS pressure less than the maximum pressure on the isothermal P/T limit curve. The RCS vent size will be re-evaluated for compliance each time the isothermal P/T limit curves are revised. The RCS vent is a passive device and is not subject to active failure. The RCS vent satisfies Criterion 2 of 10CFR50.36(c)(2)(ii). MILLSTONE - UNIT 3 B 3/4 4-21 Amendment No. XY7, 197 0782

REACTOR COOLANT SYSTEM BASES OVERPRESSURE PROTECTION SYSTEMS (continued) LCO This LCO requires that cold overpressure protection be OPERABLE and the maximum mass input be limited to one charging pump. Failure to meet this LCO could lead to the loss of low temperature overpressure mitigation and violation of the reactor vessel isothermal P/T limits as a result of an operational transient. To limit the mass input capability, the LCO requires a maximum of one centrifugal charging pump capable of injecting into the RCS. The elements of the LCO that provides low temperature overpressure mitigation through pressure relief are:

1. Two OPERABLE PORVs; or A PORV is OPERABLE for cold overpressure protection when its block valve is open, its lift setpoint is set to the nominal setpoints provided for both three and four loops unisolated by Figure 3.4-4a or 3.4-4b and when the surveillance requirements are met.

2. Two OPERABLE RHR suction relief valves; or An RHR suction relief valve is OPERABLE for cold overpressure protection when its isolation valves from the RCS are open and when its setpoint is at or between 426.8 psig and 453.2 psig, as verified by required testing.

3. One OPERABLE PORV and one OPERABLE RHR suction relief valve; or

4. A depressurized RCS and an RCS vent.

An RCS vent is OPERABLE when open with an area of > 2.0 square inches. Each of these methods of ovepressure prevention is capable of mitigating the limiting cold overpressure transient. MILLSTONE - UNIT 3 B 3/4 4-22 Amendment No. W7, 197 0782

LBDCR No. 04-MP3-015 February 24, 2005 VEACTOR COOLANT SYSTEM BASES OVXRPRESSURE PROTECI ION SYSTEMS tcontinued) APPLICABILI This LCO is applicable In MODE 4 when any RCS cold leg temperature is 5 2260 F, in MODE 5, and in MODE 6 when the head is on the reactor vessel. The Pressurizer safety valves provide RCS ovmpessure protection in the ductile region (ie.> 2260F). When the reactor head is off, ovexpressurization cannot occur. LCO 3A.9.1 "Pressure/Temperature Limits" provides the operational P/T limits for all MODES. LCO 3A.2, "Safety Valves," requires the OPERABLITY of the Pressurizer safety valves that provide overpressure protection during MODES 1,2, and 3, and 4 when all RCS cold leg temperatures are > 226°F. Low temperature overpressure prevention is most critical during shutdown when the RCS is water solid, and a mass or heat input transient can cause a rapid increase in RCS pressure when little or no time exists for operator action to mitigate the event. ACflOHS With two or more centrifugal charging pumps capable of injecting into the RCS, or with any SIH pump capable of inWecting into the RCS, RCS ovexpressurization is possible. To Immediately initiate action to restore restricted mass input capability to the RCS reflects the urgency of removing the RCS from this condition. Required ACION a. is modified by a Note that permits two centrigal charging pumps capable of RCS injection for S I hour to allow for pump swaps. This is a controlled evolution ofshort duration and 1he procedure prevents hating two charging pumps simultaneously out of pull-to-lock while both charging pumps ar capable of injecting into the RCS. Il MODE 4 when any RCS cold leg temperature is S 226'F, with one required relief valve Inoperable, the RCS relief valve must be restored to OPERABLE status within an allowed outage time (AOT) of 7 days. Two relief valves in any combination of the PORVs and the RHR suction relief valves are required to provide low temperature overpressure mitigation while withstanding a single failure of an active component. MiLLSTONE - UNIT 3 B 314 4-23 Amendment No. 4S, 49, Icjo Ohaaob Oq

REACTOR COOLANT SYSTEM BASES OVERPRESSURE PROTECTION SYSTEMS (continued) The AOT in MODE 4 considers the facts that only one of the relief valves is required to mitigate an overpressure transient and that the likelihood of an active failure of the remaining valve path during this time period is very low. The RCS must be depressurized and a vent must be established within the following 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> if the required relief valve is not restored to OPERABLE within the l required AOT of 7 days. d. The consequences of operational events that will overpressurize the RCS are more severe at lower temperatures (Ref. 8). Thus, with one of the two required relief valves inoperable in MODE 5 or in MODE 6 with the head on, the AOT to restore two valves to OPERABLE status is 24 hours1 days <br />0.143 weeks <br />0.0329 months <br />. The AOT represents a reasonable time to investigate and repair several types of relief valve failures without exposure to a lengthy period with only one OPERABLE relief valve to protect against overpressure events. The RCS must be depressurized and a vent must be established within the following 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> if the required relief valve is not restored to OPERABLE within the required AOT of 24 hours1 days <br />0.143 weeks <br />0.0329 months <br />. e. The RCS must be depressurized and a vent must be established within 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> when both required Cold Overpressure Protection relief valves are inoperable. The vent must be sized > 2.0 square inches to ensure that the flow capacity is greater than that required for the worst case cold overpressure transient reasonable during the applicable MODES. This action is needed to protect the RCPB from a low temperature overpressure event and a possible non-ductile failure of the reactor vessel. The time required to place the plant in this Condition is based on the relatively low probability of an overpressure event during this time period due to increased operator awareness of administrative control requirements. SURVEILLANCE REQUIREMENTS 4.4.9.3.1 Performance of an ANALOG CHANNEL OPERATIONAL TEST is required within 31 days prior to entering a condition in which the PORV is required to be OPERABLE and every 31 days on each required PORV to verify and, as necessary, adjust its lift setpoint. The ANALOG CHANNEL OPERATIONAL TEST will verify the setpoint in accordance with the nominal values given in Figures 3.4-4a and 3.4-4b. PORV actuation could depressurize the RCS; therefore, valve operation is not required. MILLSTONE - UNIT 3 B 3/4 4-24 Amendment No. Gyp, 197 0782

REACTOR COOLANT SYSTEM BASES OVERPRESSUFRE PPGTL7iOt_ A ST I Pearfoe a; & a, .lt~ilEL ! + .L; .

                                       'r-:I,       ..-       J- -, !  +n     ^     ;

, quril once pt 24l-n- i] :r,. val He opens, waithrin the  ; .eq The PORV block valve must be i;eri ied pen 4 t , 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> to provide a flow path and a coIw E?rpsu r prot ctionn~acuatiD circuit for each required PORV to perform, i' fur, ion w.hen r-qui 1d The val ve is remotely verified open in the main conrol room. This Surveillance performed if credit is being taken for the PORV to satisfy the LCO. The block valve is a remotely controlled. -otor operated valve. The poeer to thre valve operator is not required to be reMoved, and the manual operator is not required to be locked in the open position Thus. the block valve can be Closed in the event the PORV develops excessive leakage or does not close (sticks open) after relieving an overpressure transient. The 72 hour Frequency is considered adequate in view of other, adminiStrati.e controls available to the operator in the control room, such as valve poSition indication. that verify the PORV block valve remains open. 4.4.9.3.2 Each required RHR suction relief valve shall be demonstrated OPERABLE by verifying the RHR suction valves, 3RHS*MV8701A and 3RHS*M8701C, are open when suction relief valve 3RHS*RV8708A is being used to meet the LCO and by verifying the Ri:R suction :alves, 3RHS*MV8702B and 3RHS*MV8702C, are open when sucti n relief valve 3RHS*RV8708B is being used to meet the LCO. Each required RHR suction relief valve shall also be demonstrated OPERABLE by testing it in accordance with 4.0.5. This Surveillance is only required to be performed if the RHR suction relief valve is being used to meet this LCO. The RHR suction valves are verified to be open every 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />. The Frequency is considered adequate in view of other administrative controls such as valve status indications available to the operator in the control room that verify the RHR suction valves remain open. The ASME Code, Section XI (Ref. 9), test per 4.0.5 verifies OPERABILITY by proving proper relief valve mechanical motion and by measuring and, if required, adjusting the lift setpoint. M0ILSTONE - UNIT 3 B 3/4 4- 25 Amendment No. 1g7, 797, 206 0864

REACTOR COOLANT SYSTEM BASES OVERPRESSURE PROTECTION SYSTEMS (continued) 4.4.9.3.3 The RCS vent of > 2.0 square inches is proven OPERABLE by verifying its open condition either:

a. Once every 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> for a vent valve that cannot be locked open.

b. Once every 31 days for a valve that is locked, sealed, or secured in position or any other passive vent path. A removed Pressurizer safety valve fits this category.

This passive vent arrangement must only be open to be OPERABLE. This Surveillance is required to be performed if the vent is being used to satisfy the pressure relief requirements of the LCO. 4.4.9.3.4 and 4.4.9.3.5 To minimize the potential for a low temperature overpressure event by limiting the mass input capability, all SIH pumps and all but one centrifugal charging pump are verified incapable of injecting into the RCS. The SIH pumps and charging pumps are rendered incapable of injecting into the RCS through removing the power from the pumps by racking the breakers out under administrative control. Alternate methods of control may be employed using at least two independent means to prevent an injection into the RCS. This may be accomplished through any of the following methods: 1) placing the pump in pull to lock (PTL) and pulling its UC fuses, 2) placing the pump in pull to lock (PTL) and closing the pump discharge valve(s) to the injection line, 3) closing the pump discharge valve(s) to the injection line and either removing power from the valve operator(s) or locking manual valves closed, and 4) closing the valve(s) from the injection source and either removing power from the valve operators or locking manual valves closed. An SIH pump may be energized for testing or for filling the Accumulators provided it is incapable of injecting into the RCS. The Frequency of 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> is sufficient, considering other indications and alarms available to the operator in the control room, to verify the required status of the equipment. REFERENCES

1. ASME Boiler and Pressure Vessel Code, Section XI, Appendix G, "Fracture Toughness for Protection Against Failure," 1995 Edition.

2. ASME Section XI, Code Case N-640, "Alternative Reference Fracture Toughness for Development of P-T Limit Curves," dated February 26, 1999.

3. Generic Letter 88-11

4. ASME, Boiler and Pressure Vessel Code, Section III

5. FSAR, Chapter 15

6. 10CFR50, Section 50.46

7. 10CFR50, Appendix K

8. Generic Letter 90-06

9. ASME, Boiler and Pressure Vessel Code, Section XI MILLSTONE - UNIT 3 B 3/4 4-26 Amendment No. 7 , 197 0782

This page intentionally left blank MILLSTONE - UNIT 3 B 3/4 4-27 Amendment No. fF, FF, II?, 197, 0794 I77, 204 I

LBDCR No. 04-fP3-015 Febnrary 24,2005 314.5 EMRGE TCY CORE COOLING SYSTEMS BASES 34.51 -ACM ATQR The OPERABILITY of each Reactor Coolant System (RCS) aculator ensures that a sufficient volume of borated water will be immediately forced into the reactor core through each of the cold legs in the event the RCS pressure falls below the pressure ofthe accumulators. This initial surge of water into the core provides the initial cooling mechanism during large RCS pipe ruptures. The limits on accumulator volume, boron concentration and pressure ensure that the assumptions used for accumulator irjection in the safety analysis are met. The accumulator power perated isolation valves are required to meet the guidance of opaingbypasses" in th context of MEE Std. 279-1971, w hich requesthatbypasses of a protectivefmction be removed automatically whenever permissive conditions are not met. The uoperating bypass" designed for the isolation valves is applicable to MODES 1,2, and 3 with Pressurizer pressure above P-ll selpoint. Io addition, as these accumulator isolation valves fail to meet single failure criteria, removal of power to the valves is required. The limits for operation with an accumulator Inoperable for any reason except an isolation valve closed minimies the time exposure of the plant to a LOCA event occurring concurrent with failure of an additional accumulator which may result in unacceptable peak cladding temperatures. If a dosed isolation valve cannot be immediately opened, the full capability of one accumulator is not available and prompt action is required to pltce the reactor Ina mode where this capability is not required. 3/4.5.2 AND 3145-3 ECCS SUBSYSTEMS The OPERABIlTY oftwo independent ECCS subsystems ensures that sufficient emergency core cooling capability illbe available inthe event ofa LOCA assuming the loss of one subsystem through any single failure consideration. Either subsystem operating in conjunction with the accumulators is capable ofsupplying sufficient co cooling to limit the peak cladding temperatures within acceptable limits for all postulated break sizes ranging from the double ended break of the largest RCS cold leg pipe downward. In addition, each ECCS subsystem provides long-term core cooling capability in the rcwirculation mode during the accident recovery peri6d. With the RCS temperaftre below 3500F, one OPERABLE ECCS subsystem is acceptable without single,failure consideration and with some valves out ofnormal iijection lineup, on the basis of the stable reactivity condition of the reactor and the limited core cooling requirements. MILLSTONE - UN1T 3 B 314 5-1 AmenomentNo. M bA&Z' C/?t6 a L2Las

LBDCR No. 04-MP3-015 February24,2005 NMERGENCY CORE COOQL7N SYSTEMS BASES EMS SUBSYSIEMS (Continue) The Charging Pump/Reactor Plant Component Cooling Water Pump Ventilation System is required to be avalle to support charging pump operation. ITe Charging PunpReactor Plant Como nent Cooling Water Pump Ventilation System consists of two redundant trainis, each ecof providing 100% of the required flow. Each train has a two position, 'Off' and "Auto," emote control witc. With the rmote control switches for each train in the "Auto" position, the system Iscapable of automatically transferring operation to the redundant train in the event of a low flow condition inthe operating train. The associatdd fans do not receive any safety related automatic start signals (e.g., Safety Injection Signal). Placing the remote control switch fora Charging P M actorPlant Component Cooling Water Pump Ventilation hain in the O position to start the redundant train or to perform post maintenanoc testing to verify availability othe redundant trai will not affect the availability of that train, provided appropriate administrative controls have been established to ensure the remote control switch is Immediately returned to the "AuWt position after the completion of the specified activities or in response to plant conditions. These administrative controls Include the use ofan approved procedure and a designated Individual at the control switch for the respective Charging PumpReactor Plant Component Cooling Water Pump Ventilation Train who can rapidly respond to instructions fiom procedures, or control room personnel, based on plant conditions. The Surveillance Requirements provided to ensure OPERABILITY of each component ensures that ata minimum, the assumptions used in the safety analyses are met and that subsystem OPERABILTIY is maintained. Surveillance Requirements for throttle walve position stops and flow balance testingprovide assurance thatproperECCS flows will be maintained in the event of a LOCA. Maintenance of proper flow resistance and pressure drop in the piping system to each injection point is necessary to: (I) prevent total pump flow from exceeding runout conditions when the syste Is in its minimum resistance configuration, (2) provide the proper flow split between inection points in accordance with the assmptions used in the ECCS-ISXCA analyses an ) proide an aceptable level of total ECCS flow to all injection points equal to or above that assumed inthe ECCS-LOCA analyses. Surveillance Requirement 4.S.2b.l requires verifying that the ECCS piping is full of water. The ECCS pumps are nom ina standby, uonopeating mode, with the exception of the operating centrifgal pum g s). As such, theECCS flowpath piping has the potential to develop voids and pockets of entrained gases. Mataiing the ppng from the ECCS pums to 1hi RCS fill of water ensures that the system will perfor prerly wrhen required to Injct into the RCS. This will also prevent waterhammei, pump cavitation, and pumping ofuoncondensible gases (e.g.a, nitrogen, or hydrogen) into the reactor vesse fo n an SI sgnal or during shutdown cooling. This Surveillance Requirement is met by: VENTG ECCS pump casings and the accessible discharge piping high points icluding the ECCS pump suction crossoverpping (i.e., downstream of valves 3RSS*MV8837AIB and 3R5SSMV8838AIB to safety injection and charging pump suction). MUSTONB - UNIT 3 B 3/4 5-2 Amendment No.40, WI,415,

                                                         ,60, (YYZ a                        esS

LBDCR No. 04-MP3-015 February 24,2005 EMEGENCY CORE COOLING SYSTEMS BASES EQS StUBSSIEMS (Continued)

• VENTNG of the nonoperating centrifgal charging pumps at the suction line test J connection. The nonoperating centrifgal charging pumps do not have casing vent comections and VENING the suction pipe wIll assure that the pump casing does not contain voids and pockets of entrained gases.
• using an external water level detection method for the water filled portions of the RSS piping upstream of valves 3RSS*MV8837A/B and 3RSS*MV8838A/B. When deemed necessary by an extrnal water level detection method, filling and venting to reestablish the acceptable water levels may be performed after entering LCO ACTION statement 3.622 since VENTING without isolation of the affected train would result in a breach of the containment pressure boundary.

Ile following ECCS subsections are exempt from this Surveillance:

• the operating centrifugal chargingpump(s) and associated piping - as an opeating pump is self VENTING and cannot develop voids and pockets of entrained gases.
• the RSS pumps, since this equipment is partially dewatered-during plant operation.
• the RSS heat exchangers, since this equipment is laid-up dry during plant operation.
• the RSS piping that is not maintained filled with water during plant operation.

Surveillance Requirement 452.C2 requir that the visuil inspection of the containment be performed at least once daily if the containment has been entered that day and when the final containment entry is made. This will reduce the number of unnecessary inspections and also reduce personnel exposure. The Emergency Core Cooling System (ECCS) has several piping cross connection points for use during the post-LOCA recirculation phase of operation. These cross-connection points allow the Recirculation Spray System (RSS) to supply water fronrthe containment sump to the safety Wection and charging pumps. The RSS has the capability to supply both Train A and B safety injection pumps and both Train A and B charging pumps. Operator action is required to position valves to establish Row fiom the containment sump through the RSS subsystems to the safety injetion and charging pumps since the valves are not automatically repositioned. The quarterly stroke testing (Technical Specification 4.0.5) of the ECC.RSS recirculation flowpath valves discussed below will not result in subsystem inoperability (except due to other equipment manipulations to support valve testing) since these valves are manuially aligned in accordance with the Emergency Operating Procedures (BOPs) to establish the recirculation flowpaths. It is expected the valves will be returned to the normal pre-test position following termination of the surveillance testing in reponse to the accident. Failure to restore any valve to the normal pre-test position will be indicated to the Control Room MILLSTONE - UNIT 3 B 3t4 5-2a Amendment No. 409, 44-,47,

LBDCR No. 04-MP3-015 February24, 2005 EMERGENCY CORE CQOL1NG SYSTEMS BASES ECCS SEBSYliMS (Continued) Operators when the ESF status panels are checked, as directed by the EOPs. The EOPs direct the Control Room Operators to check the ESF status panels early in the event to ensure proper equipment alignment Sufficient tizme before the recirculation flowpath is required is expected to be available for operator action to position any valves that have not been restored to the pretest position, including local manual valve operatioL Even if the valves ame not restored to the pre-test position, suficient capability will remain to meet ECCS post-LOCA recirculation requirements. Asart, sketestigofthe ECCS recirculation valves discussed below will not result in a loss of system independence or redundancy, and both ECCS subsystems will remain OPERABLE. When performing the quarterly strok test of 3SIH*MV8923A, the control switch for safety injection pump 3SIH*PIA is placed InIhe pull-to-lock: position to prevent an automatic pump start wi the suction valve closedL With the control switch for 3SIH*PIA in pull-to-lock, the Train A ECCS subsystem is inoperable and Technical Specification 3.5.2, ACTION a., applies. This ACTION statement is sufficient to administratively control the plant configuration with the automatic start of 3SIH*PlA defeated to allow stroke testing of 3SIH*MV8923A. In addition, the EOPs and the ESF status panels will identify this abnormal plant configuration, if not corrected following &e termination of the surveillance testing, to the plant operators to allow restoration of the normal post-LOCA recirculation flowpath. Even if system restoration is not accomplished sufficient equipment will be available to perform all ECCS and RSS injection and recircuation fimctions, provided no additional ECCS or RSS equipment is inoperable, and an additional single failure does not occur (an acceptable assumption since the Tecihnical Specification ACTION statement limits the pait configuration time such that no additional equipment failure need be postulated). During the injection phase the redundant subsystem (Train B) is flly functional, as is a ignificant portion of the TrainA subsystem. During the recirculation phase, the Train A RSS subsystem can supjly water from the containment sump to the Tmin A and B charging pumps, and the Trin B RSS subsystem can supply water from the containment SUMp to theB safetyinjectionpump. When performing the quarterly stroke test of3SlH*MV8923B, the control switch for safety injection pump 3SIH*PIB Is placed in the pull-to-lock position to prevent an automatic pump start with the suction valve closed. Wth the control switch for 3SII*PIB in pull-to-lock, the Thin B ECCS subsystem is inoperable aid Technical Specification 3.5.2, ACTION a., applies. This ACT1ON statement is sufficient to administratively control the plant conflguration with the automatic start of3SIH*FPB defeated to allow stoke testing of 3SIH*MV8923B. In addition, the EOPs and the ESF status panels will identify this abnormal plant configuration, if not corrected following the termination of the surveillance testing, to the plant operators to allow restoration of the normal post-LOCA recimrlation flowpath. Even if system restoration is not accomplished, sufficient equipment will be available to perform all ECCS and RSS injection and recirculation finctions, provided no additional ECCS orRSS equipment IsInoperable, and an additional single failure does not occur (an acceptable assumption since the Technical Specification ACTION statement limits the plant confguration time such that no additional equipment filure need be postulated). During the injection MLLSTONE - UNIT 3 B 3/4 5-2b Amendment No. +0,447, 4-n,

EMERGENCY CORE COOLING SYSTEMS -LBDCR 3-7-02 BASES July 3, 2002 ECCS SUBSYSTEMS (Continued) phase the redundant subsystem (Train-A) is fully functional, as is a significant portion of the Train B subsystem. During the recirculation phase, the Train A RSS subsystem can supply water from the containment sump to the Train A and B charging pumps and the Train A safety injection pump. The Train B RSS subsystem cannot supply water from the containment sump to any of the remaining pumps. When performing the quarterly stroke test of 3S1H*MV8807A or 3SIH*MV8807B, 3SIH*MV8924 is closed first to prevent the potential injection of RWST water into the RCS through the operating charging pump. When 3SIH*MV8924 is closed, it is not necessary to declare either ECCS subsystem inoperable. Although expected to be open for post-LOCA recirculation, sufficient time is expected to be available post-LOCA to identify and open 3SIH*MV8924 either from the Control Room or locally at valve. The EOPs and the ESF status panels will identify this abnormal plant configuration, if not corrected following the termination of the surveillance testing, to the plant operators to allow restoration of the normal post-LOCA recirculation flowpath. Even if system restoration is not accomplished, sufficient equipment will be available to perform all ECCS and RSS injection and recirculation functions, provided no additional ECCS or RSS equipment is inoperable, even if a single failure is postulated. The failure to open 3SIH*MV8924 due to mechanical binding or the loss of power to ECCS Train A could be the single failure. If a different single failure is postulated, restoration of 3SIH*MV8924 can be accomplished. The closure of 3SIH*MV8924 has no affect on the injection phase. During the recirculation phase, assuming 3SIH*MV8924 remains closed (i.e., the single failure), the Train A RSS subsystem can supply water from the containment sump to the Train A and B charging pumps, and the Train B RSS subsystem can supply water from the containment sump to the Train A and B safety injection pumps. If power is lost to ECCS Train A and 3SIH*MV8924 is not opened locally (i.e., the single failure), cold leg recirculation can be accomplished by using RSS Train B to supply containment sump water via 3SIH*P1B to the RCS cold legs and 3SIL*MV8809B can be opened to supply containment sump water via RSS Train B to the RCS cold legs. Hot leg recirculation can be accomplished by using RSS Train B to supply containment sump water via 3SIH*PIB to the RCS hot legs and maintaining 3SIL*MV8809B open to supply containment sump water via RSS Train B to the RCS cold legs. MILLSTONE - UNIT 3 B 3/4ri. 5-2c _ - - J L Amendment No. 100, T47. 11 Y97.

LBDCR No. 04-MP3.015 February 24,2005 FMERGENCY CORE COOLNG SYSTEMS BASES EQCCS Subsystems: Auxiliary Building RPCCW Ventilation Area Temperature Maintenance: Ii MODES 1, 2, 3 and 4, two trains of 4 heaters each, powered fiom class IE power supplies, are required to s charging pump OPERABLITY during cold weather conditions. These heaters are r whenever outside temperature is less than or equa1 to 170 F. When outside air temperature is below 17%F, ifboth trains of heaters inthe RPCCW Ventilation Area are available to maintain at least 651F in the Charging Pump and Reactor Component Cooling WaterPump areas of the Axiwliary Building, both charging pumps ae OPERABLE forMODES 1,2 and 3. When outside air temperature Isbelow 17F, ifone train of heaters in the RPCCW Ventilation Area is available to maintain at least 32°F in the Charging Pump and Reactor Component Cooling WaterPump areas of the Auxiliary Building, the operating chargig pump is OPERABLE, for MODE 4. With less than 4 OPERABLE heaters in either train, the corrcsponding train of charging is inoperable This condition will require entry into the applicable ACI1ON statement for LCOs 3.52 and 3.5.3. LCO 3.52 AC1ION statement ", and LCO 3.5.3 ACTION statement "c" address special reporig requirements i response to ECCS actuation with water finection to the RCS. Te special report completion is not a requirement for logging out of the ACTION statements that require Fthe reports. the OPERABILITY of the refueling water storage tank (RWSI) as part of the ECCS ensures that a sufficient supl y of borated water Is available for injection by the ECCS in the event of a LOCA. Ihe limits on RWST minimnum volume and boron concentration ensure that: (1) sufficient water is available within containment to permit recirculation cooling low to the core, and (2) the reactor will remain subcritical Inthe cold condition following a large break LE") LOCA, assuming mixing of the RWS1, RCS, ECCS water, and ot'her sourcs of water that may eventually reside in the sump, with ill control tods assumed to be out. These assumptions are consistent with the LOCA analyses. The contained water volume limit Includes an allowance for water not usable because of tank dischrge line location or other physical characteristics. The limits on contained water volume and boron concentration of the RWST also ensure a pH value of between 7.0 and 7.5 for the solution recirculated within containment after a LOCA. This pH band minimizes the effect of chloride and caustic stress corrosion on mechanical systems and components. Themadmumminim solution temperatures for the RWST inMODES 1,2,3 and 4 are based on anayis assumptions. MILLSTONE - UNIT 3 B 314 5-2d AmendmentNo.409,4.47, 46, k3 aeo Qh ea6&-,W-,l 5

EMERGENCY CORE COOLING SYSTEMS 3/4.5.5 TRISOOIUM PHOSPHATE STORAGE BASKETS BASES BACKGROUND Trisodlum phosphate (TSP) dodecahydrate is stored in porous wire mesh baskets on the floor or in the sump of the containment building to ensure that iodine, which may be dissolved in the recirculated reactor cooling water following a loss bf coolant accident (LOCA), remains in solution. TSP also helps inhibit stress corrosion cracking (SCC) of austenitic stainless steel components in containment during the recirculation phase following an accident. Fuel that is damaged during a LOCA will release iodine in several chemical forms to the reactor coolant and to the containment atmosphere. A portion of the iodine in the containment atmosphere is washed to the sump by containment sprays (i.e., Quench Spray and/or Containment Recirculation Spray). The emergency core cooling water is borated for reactivity control. This borated water causes the sump solution to be acidic. In a low pH (acidic) solution, dissolved iodine will be converted to a volatile form. The volatile iodine will evolve out of solution into the containment atmosphere, significantly increasing the levels of airborne iodine. The increased levels of airborne iodine in containment contribute to the radiological releases and increase the consequences from the accident due to containment atmosphere leakage. After a LOCA, the components of the core cooling and containment spray systems will be exposed to high temperature borated water. Prolonged exposure to the core cooling water combined with stresses imposed on the components can cause SCC. The SCC is a function of stress, oxygen and chloride concentrations, pH, temperature, and alloy composition of the components. High temperatures and low pH, which would bs present after a LOCA, tend to promote SCC. This can lead to the failure of necessary safety systems or components. Adjusting the pH of the recirculation solution to levels above 7.0 prevents a significant fraction of the dissolved iodine from converting to a volatile form. The higher pH thus decreases the level of airborne iodine in containment and reduces the radiological consequences from containment atmosphere leakage following a LOCA. Maintaining the solution pH 2 7.0 also reduces the occurrence of SCC of austenitic stainless steel components in containment. Reducing SCC reduces the probability of failure of components. Granular TSP dodecahydrate is employed as a passive form of pH control for post LOCA containment spray and core cooling water. Baskets of TSP are placed on the floor or in the sump of the containment building to dissolve MILLSTONE UNIT NO. 3 B 3/4 5-3 Amendment No. 115 am0 dAY 2 6 1 95

EMERGENCY CORE COOLING SYSTEMS BASES (continued) BACKGROUND (continued) from released reactor coolant water and containment sprays after a LOCA. Recirculation of the water for core cooling and containment sprays then provides mixing to achieve a uniform solution pH. The dodecahydrate form of TSP is used because of the high humidity in the containment building during normal operation. Since the TSP is hydrated, it is less likely to absorb large amounts of water from the humid atmosphere and will undergo less physical and chemical change than the anhydrous form of TSP. APPLICABLE SAFETY ANALYSES The LOCA radiological consequences analysis takes credit for iodine retention in the sump solution based on the recirculation water pH being a 7.0. The radionuclide releases from the containment atmosphere and the consequences of a LOCA would be increased if the pH of the recirculation water were not adjusted to 7.0 or above. LIMITING CONDITION FOR OPERATION The TSP is required to adjust the pH of the recirculation water to 2 7.0 after a LOCA. *A pH 2 7.0 after a LOCA is necessary to prevent significant amounts of iodine released from fuel failures and dissolved in the recirculation water from converting to a volatile form and evolving into the containment atmosphere. Higher levels of airborne iodine in containment may increase the release of radionuclides and the consequences of the accident. A pH 2 7.0 is also necessary to prevent SCC of austenitic stainless steel components in containment. SCC increases the probability of failure of components. The required amount of TSP is based upon the extreme cases of water volume and pH possible in the containment sump after a large break LOCA. The minimum required volume is the volume of TSP that will achieve a sump solution pH of 2 7.0 when taking into consideration the maximum possible sump water volume and the minimum possible pH. The amount of TSP needed in the containment building is based on the mass of TSP required to achieve the desired pH. However, a required volume is specified, rather than mass, since it is not feasible to weigh the entire amount of TSP in containment. The minimum required volume is based on the manufactured density of TSP dodecahydrate. Since TSP can have a tendency to agglomerate from high humidity in the containment building, the density may increase and the volume decrease during normal plant operation. Due to possible agglomeration and increase in density, estimating the minimum volume of TSP in containment is conservative with respect to achieving a minimum required pH. MILLSTONE UNIT NO. 3 B 3/4 5-4 Amendment No. 115 0303 MY 26 e,995

BASES (continued) APPL ['ABIL IT' Ir [-a: .!)E'i2 . -. 1 -in. ,  ;- 1'.

                                                                                                                  '           7.--t bC.LJIICIC              Ii            ree L i, c!..               .-       ,.7.
                                                                 ,,-,7<
                                                                      ,e           ,              .           -l   '            -   1 fri                                           ! -       -o                                        .    ...            ..I..,.

O ERAC*.. - . be PEC a_- sc hre r oa ther *§D. - such an accident is bt./ In MODES 5 and 6, the pcrobabil ana co nequen. cJ L w are c. ie the pressure and temperature l i mitatiJns in tihe e 1ODES. E asher these conditions. the SLCRS is not required to be OPERABLE. ACTIONS If it is discovered that the TSP in the containment buildingi sump is nut within limits, action must be taken to r-estore the TSP to Wvithin limits. During plant operation, the containment Su!-p is not a-cessible and correction may not be possible. The 7-day Completion Ti re is based on the l. probability of a DOA occurring during this period. The Completion Time is adequate to restore the volume of TSP to within the technical specification limits. If the TSP cannot be restored within limits within the 7-day Completion Time, the plant must be brought to a MODE in which the LCO does not apply. The specified Completion Times for reaching MODES 3 and 4 are those used throughout the technical specifications; they were chosen to allow reaching the specified conditions from full power in an orderly manner and without challenging plant systems. SURVEILLANCE REQUIREMENTS Surveillance Requirement 4.5.5 Periodic determination of the volume of TSP in containment must be performed due to the possibility of leaking valves and components in the containment building that could cause dissolution of the TSP during normal operation. A Frequency of once per 24 months is required to determine visually that a minimum of 974 cubic feet is contained in the TSP Storage Baskets. This requirement ensures that there is an adequate volume of TSP to adjust the pH of the post LOCA sump solution to a value > 7.0. The periodic verification is required every refueling outage, since access to the TSP baskets is only feasible during outages. Operating experience has shown this Surveillance Frequency acceptable due to the margin in the volume of TSP placed in the containment building. MILLSTONE UNIT NO. 3 B 3/4 5-5 Amendment No. Aft, 206 0865

LBDCR 03-MP3-005 December 18, 2003 314.6 CONTAWNMEWT SYSTEMS BASES 34.6.1 PRlMARYCONTAM N 314.6.1.1 CONTAINMENTlNTERITY Primary CONTAINENT INTEGRITY ensures that the release of radioactive materials from the containment atmosphere will be restricted to those leakage paths and associated leak rates assumed in the safety analyses. This restriction, in conjunction with the leakage rate limitation, will limit the SITE BOUNDARY radiation doses to within the dose guidelines of 10 CFR Part 100 during accident conditions and the control room operators dose to within the guidelines of GDC 19. Primary CONTA IMENT INTEGPIY is required in MODES I through 4. This requires an OPERABLE containment automatic isolation valve system. In MODES 1,2 and 3 this is satisfied by the automatic containment isolation signals generated by high containment pressure, low pressurizer pressure and low steamline pressure In MODE 4 the automatic containment isolation signals generated bylhigh containment pressure, low pressurizer pressure and low steamline pressure ar not required to be OPERABLE. Automatic actuation of the containment isolation system in MODE 4 is not required beause adequate time is available for plant operators to evaluate plant conditions and respond by manually operating engineered safety features components. Automatic actuation logic and actuation relays must be OPERABLE in MODE 4 to support system level manual initiation. Since the manual actuation pushbuttons portion of the containment isolation system is required to be OPERABLE in MODE 4, the plant operators can use the manual pushbuttons to rapidly postion all automatic containment isolation valves to the required accident position. Therefom, the containment isolation actuation pushbuttons satisfy the requirement for an OPERABLE containmet automatic isolation valve system in MODE 4. 3k4.6.1.2 CONTAINMENTLEAKAM The limitations on containment leakage rates, as specified in the Containment Leakage Rate Testing Program, ensure that the total containment leakage volume will not exceed the value assumed in the safety analyses at the peak accident pressure, Pa. As an added conservatism, the measured overall integrated leakage rate is fiulher limited to less than 0.75 La during performance of the periodic test to account for possible degradation of the containment leakage barriers between leakage tests. The Limiting Condition for Operation defines the limitations on containment leakage. Tle leakage rates are verified by surveillance testing as specified in the Containment Leakage Rate Testing Program, in accordance with the requirements of Appendix J. Although the LCO specifies the leakage rates at accident pressure, Pa, it is not feasible to perform a test at such an exact value for pressure. Consequently, the surveillance testing is performed at a pressure greater than or equal to Pa to account for test instrument uncertainties and stabilization changes. This conservative test pressure ensuresthat the measured leakage rates MILLSTONE - UNIT 3 B 314 6-1 Amendment No. 69, 89, 444, 54,

                                                                                               +86,240;

BASES 3'4.6.1.2 CON'TAINt1ENT LEAKAGE (c:irue-are representative of those which would occur at accIdent pre-Ss-lur-eawhile imeet inc the intent of the LCO. This test mra- 'Aioyg is inr, da~ce with the Containment Leakage Rate Testing Program. The surveillance testing for measuring leakage rate; an ie accordance with the Containment Leakage Rate Testing Proqrara. The enclosure building bypass leakage paths are listed in the "Technical Requirements Manual." The addition or deletion of the enclosure building bypas leakage paths shall be made in accordance with Section 50.59 of 10CFR50 and approved by the Plant Operations Review Committee. 3/4.6.1.3 CONTAINMENT AIR LOCKS The ACTION requirements are modified by a Note that allows entry and exit to perform repairs on the affected air lock components. This means there may be a short time during which the containment boundary is not intact (e.g., during access through the OPERABLE door). The ability to open the OPERABLE door. even if it means the containment boundary is temporarily not intact, is acceptable due to the low probability of an event that could pressurize the containment during the short time in which the OPERABLE door is expected to be open. After each entry and exit. the OPERABLE door must be immediately closed. ACTION a. is only applicable when one air lock door is inoperable. With only one air lock door inoperable. the remaining OPERABLE air lock door must be verified closed within 1 hour. This ensures a leak tight containment barrier is maintained by use of the remaining OPERABLE air lock door. The 1 hour requirement is consistent with the requirements of Technical Specification 3.6.1.1 to restore CONTAINMENT INTEGRITY. In addition, the remaining OPERABLE air lock door must be locked closed within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> and then verified periodically to ensure an acceptable containment leakage boundary is maintained. Otherwise, a plant shutdown is required. ACTION b. is only applicable when the air lock door interlock mechanism is inoperable. With only the air lock interlock mechanism inoperable. an OPERABLE air lock door must be verified closed within 1 hour. This ensures a leak tight containment barrier is maintained by use of an OPERABLE air lock door. The 1 hour requirement is consistent with the requirements of Technical Specification 3.6.1.1 to restore CONTAINMENT INTEGRITY. In addition, an OPERABLE air lock door must be locked closed within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> and then verified periodically to ensure an acceptable containment leakage boundary is maintained. Otherwise, a plant shutdown is required. In addition, entry into and exit from containment under the control of a dedicated individual stationed at the air lock to ensure that only one door is opened at a time (i.e., the individual performs the function of the interlock) is permitted. ACTION c. is applicable when both air lock doors are inoperable, or the air lock is inoperable for any other reason excluding the door interlock mechanism. With both air lock doors inoperable or the air lock otherwise inoperable. an evaluation of the overall containment leakage rate per Specification 3.6.1.2 MILLSTONE - UNIT 3 B 3/4 6-la Amendment No. by, By, JAg, 0802 Z77, 199, 205

BASES 3/4.6.1.3 CONTAINtM1ENJT AIR LOCKS (continued) shall be initiated immediately. and an. iir lock door must be veified closed within I hour. An evaluation is acceptable ince it is overly conservative to immediately declare the containment inoperable if both doors in the air lock have failed a seal test or if overall air lock leakage is not ;*.ithin limits. In man,' instances (e.g.. only one seal per door has failed), containment remains OPERABLE, yet only I hour' (per- Specification 3.6.1.1) would be provided to restoro the air lock to OPERABLE status prior to requiring a plant bhutdown. In addition, even with both doors failing the seal test. the overall containment leakage rate can still be within limits. The 1 hour requirement is consistent with the requirements of Technical Specification 3.6.1.1 to restore CONTAINfMENJT INTEGRITY. In addition. the air lock and/or at least one air lock door must be restored to OPERABLE status within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> or a plant shutdown is required. Surveillance Requirement 4.6.1.3.a verifies leakage through the containment air lock is within the requirements specified in the Containment Leakage Rate Testing Program. The containment air lock leakage results are accounted for in the combined Type B and C containment leakage rate. Failure of an air lock door does not invalidate the previous satisfactory overall air lock leakage test because either air lock door is capable of providing a fission product barrier in the event of a design basis accident. The limitations on closure and leak rate for the containment air locks are required to meet the restricticns on CONTAINtMENIT INTEGRITY and containmlent leak rate. Surveillance testing of the air lock seals is performed in accordance with the Containment Leakage Rate Testing Program, which ensures that the overall air lock leakage will not become excessive due to seal damage during the intervals between air lock leakage tests. While the leakage rate limitation is specified at accident pressure. P. the actual surveillance testing is performed by applying a pressure greater than or equal to Pa, This higher pressure accounts for test instrument uncertainties and test volume stabilization changes which occurs under actual test conditions. 3!4.6.1.4 and 374.6.1.5 AIR PRESSURE and AIR TEMPERATURE The limitations on containment pressure and average air temperature ensure that: (1) the ,

• ainment structure is prevented from exceeding it.

design negative pressure of 8 psia. and (2) the containment peak pressure does not exceed the design pressure of 60 psia during LOCA conditions. Measure-ments shall be made at all listed locations. whether by fixed or portable instruments, prior to determining the average air temperature. The limits on the pressure and average air temperature are consistent with the assumptions of the safety analysis. The minimum total containment pressure of 10.6 psia is determined by summing the minimum permissible air partial pressure of 8.9 psia and the maximum expected vapor pressure of 1.7 psia (occurring at the maximum permissible containment initial temperature of 120'F). MILLSTONE - UNIT 3 B 3/4 6-lb Amendment No. Up ii 7t, 0802 J77, M.205

CONTAINMENT SYSTEMS LBDCR 3-17-01 February 14, 2002 BASES 3/4.6.1.6 CONTAINMENT STRUCTURAL INTEGRITY This limitation ensures that the structural integrity of the containment will be maintained comparable to the original design standards for the life of the facility. Structural integrity is required to ensure that the containment will withstand the maximum pressure of 60 psia in the event of a LOCA. A visual inspection, in accordance with the Containment Leakage Rate Testing Program, is sufficient to demonstrate this capability. 3/4.6.1.7 CONTAINMENT VENTILATION SYSTEM The 42-inch containment purge supply and exhaust isolation valves are required to be locked closed during plant operation since these valves have not been demonstrated capable of closing during a LOCA or steam line break accident. Maintaining these valves closed during plant operations ensures that excessive quantities of radioactive materials will not be released via the Containment Purge System. To provide assurance that these containment valves cannot be inadvertently opened, the valves are locked closed in accordance with Standard Review Plan 6.2.4 which includes mechanical devices to seal or lock the valve closed, or prevents power from being supplied to the valve operator. The Type C testing frequency required by 4.6.1.2 is acceptable, provided that the resilient seats of these valves are replaced every other refueling outage. 3/4.6.2 DEPRESSURIZATION AND COOLING SYSTEMS 3/4.6.2.1 and 3/4.6.2.2 CONTAINMENT QUENCH SPRAY SYSTEM and RECIRCULATION SPRAY SYSTEM The OPERABILITY of the Containment Spray Systems ensures that containment depressurization and iodine removal will occur in the event of a LOCA. The pressure reduction, iodine removal capabilities and resultant containment leakage are consistent with the assumptions used in the safety analyses. LCO 3.6.2.2 One Recirculation Spray System consists of:

• Two OPERABLE containment recirculation heat exchangers
• Two OPERABLE containment recirculation pumps The Containment Recirculation Spray System (RSS) consists of two parallel redundant subsystems which feed two parallel 360 degree spray headers. Each subsystem consists of two pumps and two heat exchangers. Train A consists of 3RSS*PIA and 3RSS*P1C. Tain B consists of 3RSS*PIB and 3RSS*P1D.

MILLSTONE - UNIT 3 B 3/4 6-2 Anendment No. py, JJA, Jft, 0890 "Revised April 2, 2002"

CONTAINMENT SYSTEMS LBDCR 3-17-01 February 14, 2002 BASES The design of the Containment RSS is sufficiently independent so that an active failure in the recirculation spray mode, cold leg recirculation mode, or hot leg recirculation mode of the ECCS has no effect on its ability to perform its engineered safety function. In other words, the failure in one subsystem does not affect the capability of the other subsystem to perform its designated safety function of assuring adequate core cooling in the event of a design basis LOCA. As long as one subsystem is OPERABLE, with one pump capable of assuring core cooling and the other pump capable of removing heat from containment, the RSS system meets its design requirements. The LCO 3.6.2.2. ACTION applies when any of the RSS pumps, heat exchangers, or associated components are declared inoperable. All four RSS pumps are required to be OPERABLE to meet the requirements of this LCO 3.6.2.2. During the injection phase of a Loss Of Coolant Accident all four RSS pumps would inject into containment to perform their containment heat removal function. The minimum requirement for the RSS to adequately perform this function is to have at least one subsystem available. Meeting the requirements of LCO 3.6.2.2. ensures the minimum RSS requirements are satisfied. MILLSTONE - UNIT 3 B 3/4 6-2a Amendment No. 0890 "Revised April 2, 2002" (Ydwr

LBDCR No. 04-M3-015 February 24,2005 CWNTATNMENT SYSTMS BASES 314.6.3 CONTAINMaNT ISOLATION VALVES The OPERABILITY of the containment isolation valves ensures that the containment atmosphere will be isolated from the outside environment in the event of a release of radioactive material to the contaiment atmosphere or pressiZation ofthe ontiment and is consistent with the req ents of General Design Criteria 54 tbrou 57 of Appendix A to 10 CFR Par 50. Content isolatio within the tme limits specified for these isolation valves desiglred to close automatically ensures that the release of radioactive material to the environment willbe consistent with the assumptions used in the analyses for a LOCA. PSAR Table 6.2-65 lists all containment isolation valves. 'Ihe addition or deletion of any containment isolation valve shall be made in accordance with Section 50.59 of I0CFR50 and approved by the committee(s) as descibed in the QAP Topical Report. For the proses of mnectinthis LOO, the sat fumction of the containment isolation valves is to shut wi e time limits assed i the accident analyes. As long as the valves can shut within the time limits assumed in the accident analyses the alves are OPERABLE Where the valve position Indication does not affect the operation of the valve, the indication is not required for valve OPERABILITY under this LCO. Position indication for containment isolation valves is covered by Technical Specification 6.8.4.e., Accident Monitoring Instmentation. Failedposition indication on these valves must be restored "as soon as practicable" as requied by Tecihmca1 Speification 68SA.e3. Maintaiing the valves OPERABLE, when osition indication fails, facilitates troubleshooting and co on of the failure, allowing te indication to be restored "as soon as practicable ." With one or more penetration flow paths with one containment isolation valve inoperable, thie inotperable valve mist be restored to OPERABLEstatus or the affected penetration flow path must be isolated. The method of isolation must include Ithe use of at least one Isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and deactivated automatic valve, a closed manual valve, and a blind flange. A check valve may not be used to isolate the affccted penetration. If the containment isolation valve on a closed system becomes inoperable, the remaining barrier is a closed system since a closed system is an acceptable alternative to an automatic valve. However, actions must still be taken to meet Technical Specification ACTION 3.63A and the valve, not normally considered as a containment isolation valve, and closest to the containment wall should be put into the cdosed position. No leak testing of the alternate valve is necessary to satisf tbe ACION statement. Placing the manual valve m the closed position sufficiently deactites the penetration forTechnical Specification compliance. Closed system isolation valves applicable to Technical Specification ACTION 3.63d are included in FSAR Table 62-65, and are the isolation valves for those penetrations credited as General Design Criteria 57. The specified time (iCe, 72 hours3 days <br />0.429 weeks <br />0.0986 months <br />) of Technical Specification ACTION 3.63.d is reasonable, considering the relative stablty of the closedsystem (hence, reliability) to act as a penetration isolation bounda and thre e importance of suporting containmentOPERABlLlT duringMODESI 2,3 and4. In the evtIe affected penetration is isolated in accordance with 3.633A the affectedpenetration flowath must be verified to be Isolated on a periodic basis, (Surveillance Requirement 4.6.1.1.a). lhs Is necessary to assure leak tightness of containment and that containment penetatons requiring isolation following an accident are isolated. The frequency of once per 31 days inthis surveillance for verifying that each affected penetration flow path is Isolatea is wp iate considering the valves are operated under admistrative controls and the probability of their misalignment is low. MILLSTONE - UNIT 3 B 314 6-3 Amendment No. 28, 63, 44Z 246, hm Mhavg 6~f- c:5-'?ms

LBDCRNo. 04-MP3-015 February 24,2005 -CONTAINME SYSTEMS BASES For the purposes of meeting this LCO, neither the containment Isolation valve, nor any alternate valve on a closed system have a leakage limit associated with valve OPERABILITY. The opening of containment isolation valves on an intermittent basis under admitive controls Includes the following considerations: (1)stationing an operator, who is in constant communication with the control room, at the valve controls, (2) instucting this operator to close these valves in an accident situation, and (3)assuring that environmental conditions will not preclude access to close the valves and that this action will prevent the release of radioactivity outside the containment. The appropriate administrative controls, based on the above considerations, to allow containment isolation valves to be opened arc contained in th procedures that will be used to operate the valves. Entries should be placed Inthe Shift Manager Log when these vilves are opened or closed. However, it is not necessary to log into any Technical Specification ACTION Statement l for these valves, provided the appropriate administrative controls have been established. Opening a closed containment isolation valve bypasses a plant design feature that prevents the release of radioactivity outside the containment. Therefore, this should not be done frequently, and the time the valve is opened should be minimized. The determination of the appropriate administrative controls for containment isolation valves requires an evaluation of the expected environmental conditions. This evaluation must conclude environmental conditions will not preclude access to close the valve, and this action will prevent the release of radioactivity outside of containment through the respective penetration. When the Residual Heat Removal (RH) System is placed in service in the plant cooldown mode of operation, the RHR suction isolation remotely operated valves 3RHS*MV8701A and 31EHS*MV8701B, and/or 3RHS*MV8702A and 3RHS*MV8702B are opened. These valves are normally operated from the control room. They do not receive an automatic containment isolation closure dsgnal, but are interlocked to prevent their opening if Reactor Coolant System (RCS) pressure is greater than approximately 412.5 psia. When any of these valves are opened, either one ofthe two required licensed (Reactor Operator) control room operators can be credited as the operator required for administrative control. It is not necessary to use a separate dedicated operator. 314.6.4 COMBUSTIBLE GASCONROL Hydrogen Monitors are promded to detect high hydrogen concentration conditions that represent a potential for containment breach fiom a bydrogen explosion. Containment hydrogen concentration is also important in verifng the adequacy of mitigating actions. The requirement to perform a hydrogen sensor calibration at least every 92 days is based upon vendor recommendations to maintain sensor calibration. This calibration consists ofa two point calibration, utilizing gas containing approximately one percent hydrogen gas for one of the calibration points, and gas containing approximately four percent hydrogen gas for the other calibration point. MILLSTONE -UNIT 3 B 314 6-3a Amendment No. 28, 63- 44, ,16, A&tWL (?kCC JJ-,&6 ,

SUNIAINMENT SYSTEMS BASES . 3/4.6.4 COMBUSTIBLE GAS CONTROL (Continued) The OPERABILITY of the equipment and systems required for the detection and control of hydrogen gas ensures that this equipment will be available to maintain the hydrogen concentration within containment below its flammable limit during post-LOCA conditions. Either recombiner unit or the Mechanical Vacuum Pumps are capable of controlling the expected hydrogen generation associated with: (1) zirconium-water reactions, (2) radiolytic decomposition of water, and (3) corrosion of metals within containment. These Hydrogen Control Systems are consistent with the recommendations of Regulatory Guide 1.7, "Control of Combustible Gas Concentrations in Containment Following a LOCA," March 1971. The Post-LOCA performance of the hydrogen recombiner blowers is based on a series of equations supplied by the blower manufacturer. These equations are also the basis of the acceptance criteria used in the surveillance procedure. The required performance was based on starting containment conditions before the LOCA of 10.59 psia (total pressure), 1206F and 100% relative humidiy. The surveillance procedure shall use the following methods to verify acceptable blower flow rate:

1. Definitions and constants CFM = cubic feet per minute RPM = revolutions per minute Blower RPM = 3550 Blower ft3 /revolution = .028 ft3 Standard CFM = gas volume converted to conditions of 680 F and 14.7 psia.

2. Measure and record the following information:

Pcontainment--Average of 3LMS*P934, 935, 936, and 937 (psia) Pout--From 3HCS*PI1A or B (psia) Tc--Containment temperature (°F) Pin--Measure with a new inlet gauge or calculate from Equation 3a below (psia) scfm measured--See Procedure/Form 3613A.3-1 AP1--From Table 2 (psi) A--As found Slip Constant Accuracy--Instrument accuracy range from Table 1. MILLSTONE - UNIT 3 B 3/4 6-3b Amendment No. IF, an, 0940 IfZ, 216

LBDCR 03-MP3-005 December 18, 2003 BCONTAENMENT SYSAMS BASES 314.6.4 COMBUSTIBLB GAS CONTROL (Continue

3. Calculate as found slip constant (A)

a. Pin Pcontainment - APf b.

(cfmmeanured-Accuracy 3 1 _rl47 Tc+460j: 3550- 0.028x 0.95 JXpin x 528 J fp;ut x 414.7]- A+46Zhx 28 J 1/2 xQ(14.7 kLpin / Pin X

4. Calculate expected postaccident flow rate using A calculated in Step 3.

a. Slip RPM

              =Ax (4.937) 1 1 2 x 1.218                                                           I

b. Actual nlnet CEM ACFM .028 (3550- Slip RPM)

c. Standard CFM scfm - ACFM 0.725

d. Postaccident scfin Minimum = scfm x 0.95 I

e. Acceptance Flow Rate Postaccident scfm minimum 2 41.52 scim.

Table I AccuracylRan ge (R. 2) scfn (measured) Accuracy Range 30to<40 9.13 sefin 40toC50 6.98 scfin 50 to <60 5.81 sc&m 60 to <90 5.17 scfm Table 2 Inlet Piping L Dss (Ref 1) scfinMeasured A6f (psi) (Unadjusted) 30 .21 40 .31 50 .52 60 .73 70 1.8 80 1.28 MILLSTONE - UNIT 3 B 314 &3c Amendment No. 6, W, 26, l/k2 Jzz&5-&6a5

CONTAINMENT SYSTEMS BASES 3/4.6.4 COMBUSTIBLE GAS CONTROL (Continued)

References:

1. Calculation 90-RPS-722GM, "Flow Acceptance Criteria for 3HCS*RBNR IA/B Blowers 3HCS*CIA/B."

2. Calculation PA 90-LOE-0132GE, "Hydrogen Recombiner Flow Error Analysis."

The acceptance flow rate is the required flow rate at the worst case containment conditions 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> after the LOCA. The analysis assumes the recombiners are started no later than 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> after the accident. The 18-month surveillance shall verify the gas temperature and blower flow rate concurrently. 3/4.6.5 SUBATMOSPHERIC PRESSURE CONTROL SYSTEM 3/4.6.5.1 STEAM JET AIR EJECTOR The closure of the isolation valves in the suction of the steam jet air ejector ensures that: (1) the containment internal pressure may be maintained within its operation limits by the mechanical vacuum pumps, and (2) the containment atmosphere is isolated from the outside environment in the event of a LOCA. These valves are required to be closed for containment isolation. MILLSTONE - UNIT 3 0940 B 3/4 6-3d Amendment No. PI, J97, 216

February 14, 2002 BASES 3/4.6.6 SECONDARY CONTAINMENT 3/4.6.6.1 SUPPLEMENTARY LEAK COLLECTION AND RELEASE SYSTEM Backqround The OPERABILITY of the Supplementary Leak Collection and Release System (SLCRS) ensures that radioactive materials that leak from the primary contain-ment into the Secondary Containment following a Design Basis Accident (DBA) are filtered out and adsorbed prior to any release to the environment. SLCRS Ductwork Integrity: The Supplementary Leak Collection and Release System (SLCRS) remains OPERABLE with the following bolting configuration:

a. For 3HVR*DMPF44:

• Eight bolts properly installed on the ductwork access panels.
• At least one bolt must be installed in each corner area.
• The remaining bolts should be installed in the center area of each side.

b. For 3HVR*DMPF29:

• 12 bolts properly installed on the ductwork access panel.
• At least one bolt must be installed in each corner area.
• The remaining bolts should be approximately equally spaced along each side with two bolts per side.

With the above bolting specified for 3HVR*DMPF44 and 3HVR*DMPF29, reference (1) concluded the following:

• Any leakage around the plates is minimal and causes negligible effect on the performance of the SLCRS system.
• Assures the gasket will not be extruded from between the plate and duct flange when the SLCRS fans are started.
• The remaining bolts may be installed with the fans running.
• Provides adequate structural integrity in the seismic event based on engineering analysis.

Applicable Safety Analyses The SLCRS design basis is established by the consequences of the limiting DBA, which is a LOCA. The accident analysis assumes that only one train of the SLCRS and one train of the auxiliary building filter system is functional due to a single failure that disables the other train. The accident analysis accounts for the reduction of the airborne radioactive material provided by the remaining one train of this filtration system. The amount of fission products available for release from the containment is determined for a LOCA. The SLCRS is not normally in operation. The SLCRS starts on a SIS signal. The modeled SLCRS actuation in the safety analysis (the Millstone 3 MILLSTONE - UNIT 3 B 3/4 6-4 Amendment No. F7, 7fl, 0891 "Revised April 2, 2002" Qdd .aG.M

LBDCR No. 04-MP3-015 February 24, 2005 CNTATNMIENT SYSTEMS BASES 3J4.6.6.1 SUPPLEMNTARY LEAK )NEX~I AND REMEASE SYSTEM (Continued) FSAR Chapter 15, Section 15.6) is based upon a worst-case response time following an SI Initiated at the limiting setpoint. One train of the SLCRS in conjunction with gm Auxiliary Building Filter (ABF) system is capable of awing a negative r e (0.4 inches water gauge at thie auxiliary bulding 24'6" eevation) within 120 seconds aftera LOCA. This time includes diesl generator start nd sequencing time, ystem starp time, and time for the system to attain the required negativre pressure ale starthng. In the event of a DBA, one SLCRS is reguired to provide the um ostated iodine removal assumed in the safity analysis. Two hans of the SLCRS must be OPERABLE to ensure that at least one train will oerate, assuming Ghat the other tain is disabled byr a single-active fiilurc. The SLCRS works m conjunction with the ABF system. mnoperabli of one train of the ABF system also results in inoperability of the conespondn traino the . Therefore, wheneverLCO 3.7.9 is entereddue to theABF trainA (B) being inoperable, LO 3.6.6.1 mustbe entered due to the SLCRS train A (B) being inoperable. When a SLCRS LCO is not met, it Is not necessary to declare the secondary containment inoperable. However, in this event, it Is necessary to determine that a loss of safety function does not exist. A loss of safety function exists when, assuming no concurrent single failure, a safety function assumed in the accident analysis cannot be performed. Appleabiit. In MODES 1, 2,3, and 4., a DBA could lead to a fission product release to containment that leaks to the secondary containmenL The large break LOCA, on which this system's design is based, is a fulL-power event. Lss severe LOCAs and leakage still require t stem to be OPERABLE throughout these MODES. TM probability and secverit ofa LOA decrcase as core power and reactor coolant system pressure decrease. With the reactor shut down, the probabiliy of release of radioactity resulting from such an accident is low. In MODES S and 6, the probability and consequences ofa DBA are low due to the pressure and temperature limitations in these MODES. Under these conditions, the SLCRS is not required to be OPERABLE. ACTIONS WIth one SLRS train inoperable, the inoperable tain must be restored to OPERABLE status within 7 days. The OPERABLE train Is capable ofproviding 100 percent of the Iodine removal needs for a DBA. The 7day Completion sime isbased on consideration of such factors as the reliabilit ofthe OPERABLE redundant SLCRS train and the low probability of a DBA occurring during this period. The Complction Tume Is adequate to make most repairs. If the SLCRS cannot be restored to OPERABLE status within the requred Completion Time, the plant must be brought to a MODE in which the LCO does notapply. Toachievethis status, the plant must be brought to at least MODE 3 within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and MODES within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the requircdplant conditions from fl-power conditions in an orderly manner and without challengg plant systems. MI STONE-UNIT3 B 314 6-5 AmendmentNo. V,42, bf2ae@a 9 -K5- &6

@wl# glll- z--l BASES 3/4.6.6.1 SUPPLEMENTARY LEAK COLLECTION AND RELEASE SYSTEM (Continued) Surveillance Requirements a Cumulative operation of the SLCRS with heaters operating for at least 10 continuous hours in a 31-day period is sufficient to reduce the buildup of moisture on the adsorbers and HEPA filters. The 31:day frequency was developed in consideration of the known reliability of fan motors and con-trols. This test is performed on a STAGGERED TEST BASIS once per 31-days. b, c, e, and f These surveillances verify that the required SLCRS filter testing is performed in accordance with Regulatory Guide 1.52, Revision 2. ANSI N510-1980 shall be used in place of ANSI N510-1975 referenced in Regulatory Guide 1.52, Revision 2. Laboratory testing of methyl iodide penetration shall be performed in accordance with ASTM D3803-89 and Millstone Unit 3 specific parameters. The surveillances include testing HEPA filter performance, charcoal adsorber efficiency, system flow rate, and the physical properties of the activated charcoal (general use and following specific operations). The heater kW measured must be corrected to its nameplate rating. Variations in system voltage can lead to measurements of kW which cannot be compared to the nameplate rating because the output kW is proportional to the square of the voltage. The 720 hours30 days <br />4.286 weeks <br />0.986 months <br /> of operation requirement originates from Regulatory Guide 1.52, Revision 2, March 1978, Table 2, Note "c", which states that "Testing should be performed (1) initially, (2) at least once per 18 months thereafter for systems maintained in a standby status or after 720 hours30 days <br />4.286 weeks <br />0.986 months <br /> of system operations, and (3) following painting, fire, or chemical release in any ventilation zone communicating with the system." This testing ensures that the charcoal adsorbency capacity has not degraded below acceptable limits, as well as providing trend data. The 720 hour figure is an arbitrary number which is equivalent to a 30 day period. This criteria is directed to filter systems that are normally in operation and also provide emergency air cleaning functions in the event of a Design Basis Accident. The applicable filter units are not normally in operation and the sample canisters are typically removed due to the 18 month criteria. d The automatic startup ensures that each SLCRS train responds properly. The once per 24 months frequency is based on the need to perform this surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the surveillance was performed with the reactor at power. The surveillance verifies that the SLCRS starts on a SIS test signal. It also includes the automatic functions to isolate the other ventilation systems that are not part of the safety-related postaccident operating configuration and to start up and to align the ventilation systems MILLSTONE - UNIT 3 B 3/4 6-6 Amendment No. 97, 17y, Jgf, 206 0933

I zcuUeI .7 s A L f1Iju BASES 3/4.6.6.1 SUPPLEMENTARY LEAK COLLECTIOtN AND RELEASE SYSTEM (Continued) that flow through the secondary containment 'o the accident condition.

• The main steam valve building ventilation system isolates.
• Auxiliary building ventilation (normal) system isolates.
• Charging pump/reactor plant component cooling water pump area cooling subsystem aligns and discharges to the auxiliary building filters and a filter fan starts.
• Hydrogen recombiner ventilation system aligns to the postaccident config-uration.
• The engineered safety features building ventilation system aligns to the postaccident configuration.

References:

1. Engineering analysis, Memo MP3-DE-94-539, "Bolting Requirements for Access Panels on Dampers 3HVR*DMPF29 & 44, dated June 16, 1994.

MILLSTONE - UNIT 3 B 3/4 6-6a Amendment No. P7, O f, 0891 "Revised April 2, 2002"

                                                          ~&           6&z1

CONTAINMENT SYSTEMS BASES 3/4.6.6.2 SECONDARY CONTAINMENT The Secondary Containment is comprised of the containment enclosure building and all contiguous buildings (main steam valve building [partially], engineering safety features building [partially], hydrogen recombiner building [partially], and auxiliary building). The Secondary Containment shall exist when:

a. Each door in each access opening is closed except when the access opening is being used for normal transit entry and exit,

b. The sealing mechanism associated with each penetration (e.g.,

welds, bellows, or 0-rings) is OPERABLE. Secondary Containment ensures that the release of radioactive materials from the primary containment atmosphere will be restricted to those leakage paths and associated leak rates assumed in the safety analyses. This restriction, in conjunction with operation of the Supplementary Leak Collection and Release System, and Auxiliary Building Filter System will limit the SITE BOUNDARY radiation doses to within the dose guideline values of 10 CFR Part 100 during accident conditions. The SLCRS and the ABF fans and filtration units are located in the auxiliary building. The SLCRS is described in the Millstone Unit No. 3 FSAR, Section 6.2.3. In order to ensure a negative pressure in all areas within the Secondary Containment under most meteorological conditions, the negative pressure acceptance criterion at the measured location (i.e., 24'60 elevation in the auxiliary building) is 0.4 inches water gauge. LCO The Secondary Containment OPERABILITY must be maintained to ensure proper operation of the SLCRS and the auxiliary building filter system and to limit radioactive leakage from the containment to those paths and leakage rates assumed in the accident analyses. Applicabil itY Maintaining Secondary Containment OPERABILITY prevents leakage of radioactive material from the Secondary Containment. Radioactive material may enter the Secondary Containment from the containment following a LOCA. Therefore, Secondary Containment is required in MODES 1, 2, 3, and 4 when a design basis accident such as a LOCA could release radioactive material to the containment atmosphere. MILLSTONE - UNIT 3 03865 B 3/4 6-7 Amendment No. Fl.'-

LBDCR No. 04-MP3-015 February 24, 2005 NIAINMEBSYSTEMS BASES 314.6.6.2 SECONDARY CONTAINMNT (contued) In MODES 5 and 6, the probability and consequences of a DBA are low due to the RCS temperature and pressure limitation in these MODES. Therefore, Secondary Containment is not required in MODES S and 6. In the event Secondary Containment OPERABILITY is not maintained, Secondary Containment OPERABLITY must be restored within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br />. Twenty-fourhours is a reasonable Completion Time considering the limited leakage design of containment and the low probability of a DBA occurring during £hls time period. Therefore, it is considered that there exists no loss of safety function while in the ACTION Statement. Inoperability of the Secondary Containment does not make the SLCRS fans and filters inoperable. Therefore, while in this ACTION Statement solely due to inoperability of the Secondary Containment, the conditions and required ACrIONS associated with Specification l 3.6.6.1 (LC., Supplementary Leak Collection and Relent System) ar not required to be entered. If the Secondary Containment OPERABILITY cannot be restored to OPERABLE status within the required completion time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and to MODE 5 within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />. The allowed Completion times are reasonable, based on operating experience, to reach the required plant conditions from Mil-power conditions in an orderly manner and without challenging plant systems. Surveillance Requirements 4.6.6 2.1 Maintaining Secondary Containment OPERABLI requires maintaining each door in each access opening In a closed position except when the access opening is being used for normal entry and exit. The normal time allowed for passage of equipment and personnel through each access opening at a time is defined as no more than 5 minutes. The access opening shall not be blocked open. During this time, it is not considered necessary to enter the ACTION statement. A j S-minute time is considered acceptable since the access opening can be quickly closed without special provisions and the probability of occurrence of a DBA concurrent with equipment and/or personnel transit time of 5 minutes is low. The 31-day liequency for this survellance is based on engineering judgment and is considered adequate in view of the other indications of access opening status that are available to the operator. MlLSTONE - UNIT 3 B 314 6-8 Amendment No. A, 426,

CONTAINMENT SYSTEMS BASES 3/4.6.6.2 SECONDARY CONTAINMENT (continued) 4.6.6.2.2 The ability of a SLCRS to produce the required negative pressure during the test operation within the required time provides assurance that the Secondary Containment is adequately sealed. With the SLCRS in postaccident configuration, the required negative pressure in the Secondary Containment is achieved in 110 seconds from the time of simulated emergency diesel generator breaker closure. Time delays of dampers and logic delays must be accounted for in this surveillance. The time to achieve the required negative pressure is 120 seconds, with a loss-of-offsite power coincident with a SIS. The surveillance verifies that one train of SLCRS in conjunction with the ABF system will produce a negative pressure of 0.4 inches water gauge at the auxiliary building 24'6' elevation relative to the outside atmosphere in the Secondary Containment. For the purpose of this surveillance, pressure measurements will be made at the 24'6m elevation in the auxiliary building. This single location is considered to be adequate and representative of the entire Secondary Containment due to the large cross-section of the air passages which interconnect the various buildings within the Secondary Containment. In order to ensure a negative pressure in all areas inside the Secondary Containment under most meteorological conditions, the negative pressure acceptance criterion at the measured location is 0.4 inch water gauge. It is recognized that there will be an occasional meteorological condition under which slightly positive pressure may exist at some localized portions of the boundary (e.g., the upper elevations on the down-wind side of a building). For example, a very low outside temperature combined with a moderate wind speed could cause a slightly positive pressure at the upper elevations of the containment enclosure building on the leeward face. The probability of occurrence of meteorological conditions which could result in such a positive differential pressure condition in the upper levels of the enclosure building has been estimated to be less than 2% of the time. The probability of wind speed within the necessary moderate band, combined with the probability of extreme low temperature, combined with the small portion of the boundary affected, combined with the low probability of airborne radioactive material migrating to the upper levels ensures that the overall effect on the design basis dose calculations is insignificant. The SLCRS system and fan sizing was based on an estimated infiltration rate. The fan flow rates are verified within a minimum and maximum on a monthly basis. Initial testing verified that the drawdown criterion was met at the lowest acceptable flow rate. The new standard Technical Specification (NUREG-1431) 3.6.6.2 surveillance requirement requires that the drawdown MILLSTONE - UNIT 3 B 3/4 6-9 Amendment No. 97, 12 6 0385 fr1T - -

CONTAINMENT SYSTEMS BASES 3/4.6.6.2 SECONDARY CONTAINMENT (continued) criterion be met while not exceeding a maximum flow rate. It is assumed that the purpose of this flow limit is to ensure that adequate attention is given to maintain the SLCRS boundary integrity and not using excess system capacity to cover for boundary degradation. The SLCRS system was designed with minimal margin and, therefore, does not have excess capacity that can be substituted for boundary integrity. Additionally, since SLCRS fan flow rates are verified to be acceptable on a more frequent basis than the drawdown test surveillance, and by means of previous testing the minimum flow rate is acceptable, verifying a flow rate during the drawdown test would not provide an added benefit. Historical SLCRS flow measurements show a lack of repeatability associated with the inaccura-cies of air flow measurement. As a result, the more reliable verification of system performance is the actual negative pressure generated by the drawdown test and a measured flow rate would add little. 3/4.6.6.3 SECONDARY CONTAINMENT STRUCTURAL INTEGRITY This limitation ensures that the structural integrity of the Secondary Containment will be maintained comparable to the original design standards for the life of the facility. Structural integrity is required to provide a secondary boundary surrounding the primary containment that can be maintained at a negative pressure during accident conditions. A visual inspection is sufficient. to demonstrate this capability. MILLSTONE - UNIT 3 B 3/4 6-10 Amendment No. 07, 126 0360 I-- 5

                                                                       )    -

3/4.7 PLANT SYSTEMS LBDCR 3-9-02 Sepember 4. 2002 BASES 3/4.7.1 TURBINE CYCLE 3/4.7.1.1 SAFETY VALVES The OPERABILITY of the main steam line Code safety valves ensures that the Secondary System pressure will be limited to within 110% (1305 psig) of its design pressure of 1185 psig during the most severe anticipated system operational transient. The maximum relieving capacity is associated with a Turbine trip from 100% RATED THERMAL POWER coincident with an assumed loss of condenser heat sink (i.e., no steam bypass to the condenser). The specified valve lift settings and relieving capacities are in accordance with the requirements of Section III of the ASME Boiler and Pressure Code, 1971 Edition. The design minimum total relieving capacity for all valves on all of the steam lines is 1.579 X 107 lbs/h which is 105% of the total secondary steam flow of 1.504 X 107 lbs/h at 100% RATED THERMAL POWER. A minimum of two OPERABLE safety valves per steam generator ensures that sufficient relieving capacity is available for the allowable'THERMAL POWER restriction in Table 3.7-2. The OPERABILITY of the main steam Code safety valves is defined as the ability to open within the setpoint tolerances, relieve steam generator overpressure, and reseat when pressure has been reduced. The lift settings for the main steam Code safety valves are listed in Table 3.7-3. This table allows a + 3% setpoint tolerance (allowable value) on the lift setting for OPERABILITY to account for drift over an operating cycle. Each main steam Code safety valve is demonstrated OPERABLE with lift settings as shown in Table 3.7-3, in accordance with Technical Specification 4.0.5. During this testing, the main steam Code safety valves are OPERABLE provided the actual lift settings are within + 3% of the required lift setting. A footnote to Table 3.7-3 requires that the lift setting be restored to within + 1% of the'required lift setting following testing to allow drift during the next operating cycle. However, if the testing is done at the end of the operating cycle when the plant is being shut down for refueling, restoration to + 1% of the specified lift setting is not required for valves that will not be used (e.g., replaced) for the next operating cycle. While the lift settings are being restored to within + 1% of the required lift setting, the main steam Code safety valves remain OPERABLE provided the actual lift setting is within + 3% of the required lift setting. STARTUP and/or POWER OPERATION is allowable with safety valves inoperable within the limitations of the'ACTION requirements on the basis of the reduction in Secondary Coolant System steam flow and THERMAL POWER required by the reduced Reactor trip settings of the Power Range Neutron Flux channels. The Reactor Trip Setpoint reductions are derived on the following bases: Hi =(100/oQ) (whgA) K MILLSTONE - UNIT 3 B 3/4 7-1 Amendment No. Jjg, 0951 Revised by NRC letter dated 02./26/2004.

3/4.7 PLANT SYSTEMS LBDCR 3-9-02 SePember 4. 2002 BASES 3/4.7.1 TURBINE CYCLE 3/4.7.1.1 SAFETY VALVES (Continued) where: Hio = Safety Analysis power range high neutron flux setpoint, percent Q = Nominal NSSS power rating of the plant (including reactor coolant pump heat), Mwt K = Conversion factor, 947.82 (Btu/sec) Mwt hfg = heat of vaporization for steam at the highest MSSV opening pressure including tolerance (+ 3%) *and accumulation, as appropriate, Btu/lbm N = Number of loops in plant MILLSTONE - UNIT 3 B 3/4 7-la Amendment No. Ifl, 0951 Revised by NRC letter dated 02/26/2004.

LBDCR No. 04-MP3-15 February 24,2005 PLANT SYSTEMS BASES SAEMYT VALVES (Continued) ws Minimum total steam flow rate capability of the OPERABLE MSSVs on any one steam generator at the highest MSSV opening pressure including tolerance and accumulation, as appropriate, in lb/sec. For example, if the maximum number of inoperable MSSVs on any one steam generator Isone, then w, should be a summation ofthe capacity of the OPERABLE MSSVs at the highest OPERABLE MSSV operatingpressure, excluding the highest capacityMSSV. If the maximum number of inoperable MSSVs per steam generator is three, then w. should be a summation ofthe capacity of the OPERABLE MSSVs at the highest OPERABLE MSSV operating pressure, excludng the three highest capacity MSSVs. The following plant specific safety valve flow rates were used: SG Safety Main Steam System Valve Number Sd Pressure (psia) Flow (Qbmhrper loop) (Bank No.) _ _ _ _ _ _ _ 1 1200 893,160 2 1210 900,607 3 1220 908,055 4 1230 915,502 S 1240 922,950 3147.17.2 AUXILIARY FEEDWATER SYSTEM The OPERABLITY of the Auxiliary Feedwater (AFW) System ensures a makeup water spplyto the steam generators (SGs) to support decay beat rmovl from te Reactor Coolant SystemRCS) upon the loss of normal feedwater supply, assuming the worst case sinkle failure. F consists of two motor driven AFWpumps and one steam turbine driven AFW pumjpEac motor drien AW pump provides at £eat 50 thiAFenow capacit - - - m the accident analysis. Afler reactor shutdown, decay heat eventually decreases so that one motor driven AFW pump can provide sufficient SG makeup flow. he steam driven AFW pump has a rated capacity approximately double that ofa motor driven AFW pump and is thus defined as a 100%0 capacity pump. Given the worst case single failure, the AFW System is designed to mitigate the consequences of numerous design basis accidents, includirg Feedwater Lime Break, Loss of Normal Feedwater, Steam Generator Tube Rupturre, Main Steam Line Break, and Small Break Loss of Coolant Accident. MILLSTONE - UNIT 3 B 314 7-2 Amendment No.4K,439, 4S,

                                                     $3             6,'n8&                             -

February 14, 2002 BASES AUXILIARY FEEDWATER SYSTEM (Continued) In addition, given the worst case failure, the AFW is designed to supply sufficient makeup water to replace SG inventory loss as the RCS is cooled to less than 350F at which point the Residual Heat Removal System may be placed into operation. Surveillance Requirement 4.7.1.2.1 verifies that each AFW pump's total head at a recirculation flow test point is greater than or equal to the required total head. This surveillance ensures that the AFW pump performance has not degraded during the operating cycle. Because it is undesirable to introduce cold AFW into the steam generators while they are operating, this testing is performed with recirculation flow. This test confirms one point on the pump curve and is indicative of overall performance. This test confirms component OPERABILITY is used to trend performance and to detect incipient failures by indicating abnormal performance. The total head specified in Surveillance Requirement 4.7.1.2.1 does not include a margin for test measurement uncertainty. This consideration shall be addressed at the implementing procedure level. Motor driven auxiliary feedwater pumps and associated flow paths are OPERABLE in the following alignment during normal operation below 10% RATED THERMAL POWER.

• Motor operated isolation valves (3FWA*MOV35A/B/C/D) are open in MODE 1, 2 and 3,
• Control valves (3FWA*HV31A/B/C/D) may be throttled or closed during alignment, operation and restoration of the associated motor driven AFW pump for steam generator inventory control.

The motor operated isolation valves must remain fully open due to single failure criteria (the valves and associated pump are powered from the opposite electrical trains). The Turbine Driven Auxiliary Feedwater (TDAFW) pump and associated flow paths are OPERABLE with all control and isolation valves fully open in MODE 1, 2 and 3. Due to High Energy Line Break analysis, the TDAFW pump cannot be used for steam generator inventory control during normal operation below 10% RATED THERMAL POWER. 3/4.7.1.3 DEMINERALIZED WATER STORAGE TANK The OPERABILITY of the demineralized water storage tank (DWST) with a 334,000 gallon minimum measured water volume ensures that sufficient water is available to maintain the reactor coolant system at HOT STANDBY conditions for 10 hours0.417 days <br />0.0595 weeks <br />0.0137 months <br /> with steam discharge to the atmosphere, concurrent with a total loss-of-offsite power, and with an additional 6-hour cooldown period to reduce reactor coolant temperature to 350*F. The 334,000 gallon required water volume contains an allowance for tank inventory not usable because of tank discharge line location, other tank physical characteristics, and surveillance measurement uncertainty considerations. The inventory requirement is conservatively based on 120F water temperature which maximizes inventory required to remove RCS decay heat. In the event of a feedline break, this inventory requirement includes an allowance for 30 minutes of spillage before operator action is credited to isolate flow to the line break. MILLSTONE - UNIT 3 B 3/4 7-2a Amendment No. J97, Aid. 1y,^

                                                      "Revised April 2, 2002"

BASES 3/4.7.1.3 DEMINERALIZED WATER STORAGE TANK (Continued) If the combined condensate storage tank (CST) and DWST inventory is being credited, there are 50,000 gallons of unusable CST inventory due to tank discharge line location, other physical characteristics, level measurement uncertainty and potential measurement bias error due to the CST nitrogen blanket. To obtain the Surveillance Requirement 4.7.1.3.2's DWST and CST combined volume, this 50,000 gallons of unusable CST inventory has been added to the 334,000 gallon DWST water volume specified in LCO 3.7.1.3 resulting in a 384,000 gallons requirement (334,000 + 50,000 = 384,000 gallons). 3/4.7.1.4 SPECIFIC ACTIVITY The limitations on Secondary Coolant System specific activity ensure that the resultant offsite radiation dose will be limited to a small fraction of 10 CFR Part 100 dose guideline values in the event of a steam line rupture. This dose also includes the effects of a coincident 1 gpm primary-to-secondary tube leak in the steam generator of the affected steam line. These values are consistent with the assumptions used in the safety analyses. MILLSTONE - UNIT 3 B 3/4 7-2b Amendment No. XPI, flp, 7d9, 0893 "Revised April 2, 2002" 0*a &

BASES 3/4.7.1.5 MAIN STEAM LINE ISOLATION VALVES BACKGROUND The main steam line isolation valves (MSIVs) isolate steam flow from the secondary side of the steam generators following a high energy line break (HELB). MSIV closure terminates flow from the unaffected (intact) steam generators. One NSIV is located in each main steam line outside, but close to, containment. The MSIVs are downstream from the main steam safety valves (MSSVs) and auxiliary feedwater (AFW) pump turbine steam supply, to prevent MSSV and AFW isolation from the steam generators by MSIV closure. Closing the MSIVs isolates each steam generator from the others, and isolates the turbine, Steam Bypass System, and other auxiliary steam supplies from the steam generators. The MSIVs close on a main steam isolation signal generated by low steam generator pressure, high containment pressure, or steam line pressure negative rate (high). The MSIVs fail closed on loss of control or actuation power. Each MSIV has an MSIV bypass valve. Although these bypass valves are normally closed, they receive the same emergency closure signal as do their associated MSIVs. The MSIVs may also be actuated manually. A description of the MSIVs is found in the FSAR, Section 10.3. APPLICABLE SAFETY ANALYSIS The design basis of the MSIVs is established by the containment analysis for the large steam line break (SLB) inside containment, discussed in the FSAR, Section 6.2. It is also affected by the accident analysis of the SLB events presented in the FSAR, Section 15.1.5. The design precludes the blowdown of more than one steam generator, assuming a single active component failure (e.g., the failure of one MSIV to close on demand). The limiting temperature case for the containment analysis is the SIB inside containment, at 75% power with mass and energy releases based on offsite power available following turbine trip, and failure of the MSIV on the affected steam generator to close. At hot zero power, the steam generator inventory and temperature are at their maximum, maximizing the analyzed mass and energy release to the containment. Due to reverse flow and failure of the KSIV to close, the additional mass and energy in the steam headers downstream from the other MSIV contribute to the total release. With the most reactive rod cluster control assembly assumed stuck in the fully withdrawn position, there is an increased possibility that the core will become critical and return to power. The reactor is ultimately shut down by the boric acid injection delivered by the Emergency Core Cooling System. MILLSTONE - UNIT 3 B 3/4 7-3 Revised by NRq Letter dated July 10, 199E 0591 JLjd J(L/(

LBDCR No. 04-MP3-015 February 24, 2005 pLANT SYSTEMS BASES 3/4.7.1.5 MATN STEAM LTNE ISOLAliON VALVES (continued) Thc accident analysis compares several different SLB events against different acceptance criteria. The large SLB outside containment upstream ofthe MSIVs is limiting for offsite dose, although a break inthis short sectionofmain steambeaderhas verylowprobability. The large SLB upstream oftheMSIVathotzeropowereis helimiting caseforaposttriprturn topower. The analysis includes scenarios with offaite power available and with a loss of offiite power following turbine trip. With offsite power available, the reactor coolant pumps continue to circulate coolant tlrough the steam generators, maximizing the Reactor Coolant System cooldown. With a loss of offisite power, the response of mitigating systems is delayed. Significant single failures considered Include fMilure of an MSIV to close. The MSIVs serve only a safety fiuction and remain opcn during POWR OPERAT1ON. These valves operate under the following situations:

a. An HEILB inside containment. In order to maximize the mass and energy release into containnent, the analysis assumes that the MSIV in the affected steam generator remains open. For this accident scenario, steam is discharged into containment from all steam generators until the remaining MSIVs close. After MSIV closure, steam is discharged into containment only from the affected steam generator and from the residual steam in the main steam header dovmstream of the closed MSIVs in the unaffected loops. Closure of the MSlVs isolates the break from the unaffected steam generators.

b. A break outside of containment and upstream from the MSIVs is not a containment pressurization concern. The uncontrolled blowdown of moe than one steam generator must be prevented to limit the potential for uncontrolled RCS cooldown and positive reactivity addition. Closue of tIe MSIVs isolates the break and limits the blowdown to a single steam generators

c. A break downstream of the MSIVs will be isolated by the closure of the MSIVs.

d. Following a steam generator tube nipture, dosure of the MSJVs isolates the raptured steam generator firm the intact steam generators. In addition to minimizing radiological releases, this enables the operator to maintain the pressure ofthe steam generator with the raptured tube below the MSSV setpoints, a necessary step toward Isolating the flow through the rupture.

e The MSIVs are also utilized during other events, such as a feedwater line break This event is less limiting so faras MSIVOPERABILITY is concerned. MILLSTONE - UNIT3 B 3/4 7-4 Amendment No.449, 46,

                                                           &dd&         2/2aG?        e° N*'-49G

PLANT SYSTEMS BASES 3/4.7.1.5 MAIN STEAM LINE ISOLATION VALVES (continued) LCO This LCO requires that four MSIVs in the steam lines be OPERABLE. The MSIVs are considered OPERABLE when the isolation times are within limits, and they close on an isolation actuation signal. This LCO provides assurance that the MSIVs will perform their design safety function to mitigate the consequences of accidents that could result in offsite exposures comparable to the IOCFR100 limits or the NRC Staff approved licensing basis. APPLICABILITY The MSIYs must be OPERABLE in MODE 1 and in MODES 2, 3, and 4 except when closed and deactivated when there is significant mass and energy in the RCS and steam generators. When the MSIVs are closed, they are already performing the safety function. In MODES 1, 2, and 3 the MSIVs are required to close within 10 seconds to ensure the accident analysis assumptions are met. In MODE 4 the MSIVs are required to close within 120 seconds to ensure the accident analysis assumptions are met. An engineering evaluation has determined that a Reactor Coolant System (RCS) temperature greater than or equal to 3200F is required to provide sufficient steam energy to provide the motive force to operate the MSIVs. Therefore, below an RCS temperature of 320F the MSIVs are not OPERABLE and are required to be closed. In MODE 5 or 6, the steam generators do not contain much energy because their temperature is below the boiling point of water; therefore, the MSIVs are not required for isolation of potential high energy secondary system pipe breaks in these MODES. ACTIONS MODE 1 With one MSIV inoperable in MODE 1, action must be taken to restore OPERABLE status within 8 hours0.333 days <br />0.0476 weeks <br />0.011 months <br />. Some repairs to the MSIV can be made with the unit hot. The 8 hour Completion Time is reasonable, considering the low probability of an accident occurring during this time period that would require a closure of the MSIVs. The 8 hour Completion Time is greater than that normally allowed for containment isolation valves because the NSIVs are valves that isolate a closed system penetrating containment. These valves differ from other containment isolation valves in that the closed system provides a passive barrier for containment isolation. MILLSTONE - UNIT 3 9 3/4 7-5 Amendment No. ;jp, ;1p, ;t", 185 0703 a i '1

PLANT SYSTEMS BASES 3/4.7.1.5 MAIN STEAM LINE ISOLATION VALVES (continued) If the NSIV cannot be restored to OPERABLE status within 8 hours0.333 days <br />0.0476 weeks <br />0.011 months <br />, the plant must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in MODE 2 within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />. The Completion Times are reasonable, based on operating experience, to reach MODE 2 and to close the MSIVs in an orderly manner and without challenging plant systems. MODES 2. 3. and 4 Since the MSIVs are required to be OPERABLE in MODES 2, 3, and 4, the inoperable MSIVs may either be restored to OPERABLE status or closed. When closed, the MSIVs are already in the position required by the assumptions in the safety analysis. The MSIYs may be opened to perform Surveillance Requirement 4.7.1.5.2. The 8 hour Completion Time is consistent with that allowed in MODE 1. For inoperable MSIVs that cannot be restored to OPERABLE status within the specified Completion Time, but are closed, the inoperable MSIVs must be verified on a periodic basis to be closed. This is necessary to ensure that the assumptions in the safety analysis remain valid. The 7 day verification time is reasonable, based on engineering judgment, in view of MSIY status indications available in the control room, and other administrative controls, to ensure that these valves are in the closed position. If the MSIVs cannot be restored to OPERABLE status or are not closed within the associated Completion Time, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed at least in NODE 3 within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />, and in MODE 5 within the next 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from NODE 2 conditions in an orderly manner and without challenging unit systems. The Action Statement is modified by a note indicating that separate condition entry is allowed for each MSIV. SURVEILLANCE REQUIREMENTS 4.7.1.5.1 DELETED MILLSTONE - UNIT 3 B 3/4 7-6 Amendment No. 185

PLANT SYSTEMS BASES SURVEILLANCE REOUIREMENTS (continued) 4.7.1.5.2 This surveillance demonstrates that MSIV closure time is less than 10 seconds (120 seconds for MODE 4 only) on an actual or simulated actuation signal, when tested pursuant to Specification 4.0.5. A simulated signal is defined as any of the following engineering safety features actuation system instrumentation functional units per Technical Specifications Table 4.3-2: 4.a.1) manual initiation, individual, 4.a.2) manual initiation system, 4.c. containment pressure high-2, 4.d. steam line pressure low, or 4.e. steam line pressure - negative rate high. The MS1V closure time is assumed in the accident analyses. This surveillance is normally performed upon returning the plant to operation following a refueling outage. The test is normally conducted in MODES 3 or 4 with the plant at suitable (appropriate) conditions (e.g., pressure and temperature). The MSIVs should not be tested at power, since even a part stroke exercise increases the risk of valve closure when the unit is generating power. This surveillance requirement is modified by an exception that will allow entry into and operation in MODES 3 and 4 prior to performing the test to establish conditions consistent with those under which the acceptance criterion was generated. Successful performance of this test within the required frequency is necessary to operate in MODES 3 and 4 with the HSIVs open, to enter MODE 2 from MODE 3, and for plant operation in MODE 1. If this surveillance has not been successfully performed within the required frequency, the NSIVs are inoperable and are required to be closed. In MODE 4 only, the MSIVs can be considered OPERABLE if the closure time is less than 120 seconds. An engineering evaluation has determined that a RCS temperature greater than or equal to 320F is required to provide sufficient steam energy to provide the motive force to operate the KSIVs. Therefore, below an RCS temperature of 320*F the MSIVs are not OPERABLE and are required to be closed. MILLSTONE - UNIT 3 B 3/4 7-6a Amendment No. 1Af, Iff, 185 0703

LBDCR No. 04-MP3-015 Februazy 24, 2005 PLANT SYSTEMS BASES 3/4.7.1.6 -STEAM GENERATOR ATMOSPHEMC RELIEF BYPASS LINES The OPERABILITY of the steam generator atmospheric reliefbypass valve (SGARBV) lines provides a method to recover from a steam generator tube rupture (SCR) event during which the operator is required to perform a limited cooldown to establish adequate subcooling as a necessary step to limit the primary to secondary break flow into the ruptured steam generator. The time required to limit the primary to secondary break flow for an SGIR event is more critical ta the time required to cooldown to EHR entry conditions. Because ofthese time constraints, these valves and associated flow paths must be OPERABLE from the control room. The number ofSGARBVs required to be OPERABLE from the control room to satisfy the SGIR accident analysis requires consideration of single failure criteria. Four SGARBV are required to be OPERABLE to ensure the credited steam release pathways available to conduct a unit cooldown following a SGIR` For other design events, the SGARBVs provide a safety grade method for cooling the unit to residual heat removal (RHR) entry conditions should the preferred heat sink via the steam bypass system orthe steam generatoratmospheric reliefvalvesbeunavlable. Prior to operator action to cooldown, the main steam safety valves (MSSVs) are assumed to operate automatically to relieve steam and naintain the steam generatorpressure below design limits. Each SGARBV line consists of one SGARBV and an associated block valve (main steam atmospheric relief isolation valve, 3MSS*MOVI8AIBICID). These block valves are used in the event a steam generator atmospheric reliefalve (SGARV) or SGARBV fails to close. Because ofthe electrical power relationship between the SGARBV and the block valves, ifa block valve is maintained closed, the SGARBV flow path is inoperable because of single failure consideration. The bases for the required ACTIONS can be found in NUREG 1431, Rev. 1. Ihe LCO APPLICABILITY and ACTION statements uses the terms "MODE 4 when steam generator Isrelied upon for heat removal and ff MODE 4 without reiance upon steam generator for heat remova" his means that those steam generators which are credited for decay heat removal to comply with LCO 3A..13 (Reactor Coolant System, HOT SHUTDOWN) sall have an OPERABLE SGARBV line. See Bases Section 314A.1 for more detail. MI4L7T2 DEeTE 3D MILLSTONE -UNIT 3 B 3/4 7.7 Amendment No.4-36 ,,4,#

                                                             ,6aj-&      (W;ac "              -9zX

LBDCR 3-22-02 March 14,2002 pLANI MMTSMLS BASES 3/4.7.3 REACrOR PLANT COMPONENT COO0UNG WATER SYST7EM Thc OPERABILITY of the Reactor Plant Component Cooling Water System ensures that sufficient cooling capacity is available for continued operation of safety-related equipment during normal and accident conditions. The redundant cooling capacity ofthis system, assuming a single failure, Is consistent with the assumptions used in the safety analyses. The Charging PumpReactor Plant Component Cooling Water Pump Ventilation System is required to be available to support reactor plant component cooling water pump operation. The Charging Pumplieactor Plant Component Cooling WaterPump Ventilation System consists of two redundant trains, each capable of providing 100% of the required flow. Each train has a two position, OfTand "Auto," remote control switch. With the remote control switches for each train in the "Auto" position, the system is capable of automatically transferring operation to the redundant train in the event of a low flow condition in the operating train. The associated fans do not receive any safety related automatic itart signals (e.g, Safety Injection Signal).

       *Placing the remote control switch for a Charging PumplReactor Plant Component Cooling Water Pump Ventilation Train in the 'Off' position to start the redundant train or to perform post maintenance testing to verify availability ofthe redundant train will not affect the availability of that train, provided appropriate administrative controls have been established to ensure the remote control switch is immediately returned to the "Auto"position after the completion ofthe specified activities or in response to plant conditions. These administrative controls include the use ofan approved procedure and a designated Individual at the control switch for the respective Charging Pum npReactor Plant Component Cooling Water Pump Ventilation Train who can rapidly respond to Instructions from procedures, or control room personnel, based on plant conditions.

314.7.4 SERVICE WATER SYSM The OPERABILITY of the Service Water System ensures that sufficient cooling capacity Is available for continued operation of safety-related equipment during normal and accident conditions. The redundant cooling capacity of this system, assuming a single fiure, is consistent with te assumptions used in the safety analyses. An OPERABLE service water loop requires one OPERABLE service water pump and associated strainer. Two OPERABLE service water loops, with one OPERABLE service water pump and associated strainer per loop, nill provide sufficient core (and cont nt) decay heat removal during a design basis accident coincident with a loss of oflsite power and a single fil. MLLSTONE - UNIT 3 B 314 7-7a Amendment No. 45,

PLANT SYSTEMS BASES 3/4.7.5 ULTIMATE HEAT SINK BACKGROUND The ultimate heat sink (UHS) for Millstone Unit No. 3 is Long Island Sound. It serves as a heat sink for both safety and nonsafety-related cooling systems. Sensible heat is discharged to the UHS via the service water and circulating water systems. LIMITING CONDITION FOR OPERATION The UHS is required to be OPERABLE and is considered OPERABLE if the average water temperature is less than or equal to 75F. The limitation on the UHS temperature ensures that cooling water at or less than the design temperature (75'F) is available to either (1) provide normal cooldown of the facility or (2) mitigate the effects of accident conditions within acceptable limits. It is based on providing a 30-day cooling water supply to safety-related equipment without exceeding its design basis temperature and is consistent with the recommendations of Regulatory Guide 1.27, "Ultimate Heat Sink for Nuclear Plants,' March 1974. The Circulating Water System has six condenser inlet waterboxes, each contains a temperature measurement device. The average UHS temperature is normally obtained from the plant process computer by averaging the six Circulating Water System condenser inlet waterbox temperature measurements. Given potential condenser waterbox temperature instrumentation failure(s), or that a waterbox is not operating or a process computer failure, other methods may be used to determine the average UHS temperature. For example, if one condenser waterbox instrument has failed, the average UHS temperature may be based on five condenser inlet waterbox temperature measurements. For the purposes of determining average UHS temperature, if condenser waterbox inlet temperature is used, the average should be based on no less than 3 measurements. If the process computer condenser waterbox inlet temperature average is based on less than three measurements, the average is automatically flagged to users as potentially in error. Using local Service Water System temperature instruments (two or more) is an acceptable alternative for determining average UHS temperature. It has been concluded that using the average of multiple condenser waterbox inlet temperature measurements is sufficiently representative of the UHS temperature to assure OPERABILITY of the UHS. The only exception to this conclusion is when a condenser thermal backwash evolution is being conducted. During this evolution, there is a potential for significant intake structure temperature stratification. Therefore, during condenser thermal backwashing evolutions, the average UHS temperature shall be monitored by temperature instruments in the service water system to assure OPERABILITY of the UHS. APPLICABILITY In MODES 1, 2, 3, AND 4, the UHS is required to support the OPERABILITY of the equipment serviced by the UHS and required to be OPERABLE in these MODES. MILLSTONE - UNIT 3 B 3/4 7-8 Amendment No. 136 0609

LBDCR No. 04-MP3-015 February 24, 2005 PLAMT SYSTEMS BASES AMlON STATRMR4T When the UHS temperature is above 750F, the ACTION Statement for the LCO requires that the UHS temperature be monitored for 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />, and the plant be placed in at least HOT STANDBY within the next six hours end in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br /> in the event the UHS temperature does not drop below 750F during the 12-hour monitoring period. The 12-hour interval Is based on operating experience related to trending of the parameter variations during the applicable MODES. During this period, the UHS temperature will be monitored on an increased fequency. If the trend shows improvement, and if the trend of the UHS temperature gives reasonable expectations that the temwperatre will decrease below 75'1F during the 12 hour monitoring period, the UHS temperature will be continued to be monitored during the remaining portion of the 12-hour period. However, if it becomes apparent that the UHS temperature will remain above 7SF throughout the 12-hour monitoring period, conservative action regarding compliance with the ACTION Statement should be taken. An evaluation was conducted to quay the risk significance of various Chapter 15 initiating events and earthquakes during periods of elevated UHS temperature. It concluded that a seismic event was not credible for the time periods with elevated URS temperature Wilh respect to the service water loads, the limiting Condition II and m Chapter 15 event initiators are those that add additional heat loads to the service water system. A loss of offhite power event is limiting because of the added loads due to the diesel generator and the residual heat removal heat exchanger. A steam generator tube rupture event is limiting because of the addition of the safety injection and diesel generator loads without isolation ofthe trine plant component cooling water loads (no loss of offsite power or containment depr on actuation signal). Although the risk significance of a Condition IV accident occurring during the period of elevated UHS temperature is considered to be negligibly small compared to that of Condition II and m events, aLoss of Coolant Accidentwith or without a LOP was also evaluated. These scenarios have been evaluated with the additional consideration of a single failure The evaluation investigated whether or not these evtnts could be resolved with an elevated UHS temperature It was determined that Millstone Unit No. 3 could recover from these events, even with an elevated temperature of 770F. This evaluation provides the basis for the ACTION statement requirement to place the plant in HOT STANDBY within six hours and in COLD SHUMDOWN within the next 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />, ifthe UHS temperature goes above 77°F during the 12-hour monitoring period. MLLSTONE - UNIT3 B 314 7-9 Amendient No. 436, t@a e -LcV22* -

LEBDCR No. 04-MP3-015 February 24, 2005 PLANT SYSTEMS BASES SMVTLANCE REOLURBMENTS For the surveillance ents, the UHS temperature is measured at the locations descnrbed in the LCO write-up provided in this section. Surveillance Requirement 4.7.5.a verifies that the UHS is capable of providing a 30-day cooling water supply to safety-related equipment without exceeding its design basis temperature. The 24-hour frequency is based on operating experience related to trending of the parameter variations during the applicable MODES. Ibis surveillance requirement verifies that the average water temperature of the UHS is less than or equal to 750F. Surveillance Requirement 4.7.5b requires that the UHS temperature be monitored on an increased frequency whenever the UHS temperature is greater than 70F during the applicable MODES. The Intent of this Surveillance Requirement is to increase the awareness of'plant personnel regarding UHS temperature trends above 700 F. The frequency is based on operating expeience related to trending oftheparametervariations during the applicable MODES. 31:4.7.61213WITI 3J4.7.7 CON7ROIL ROOM EMRONY YEN17A7 1N SYSTEM BACKGROUND The control room emergency ventilation system provides a protected environment from which operators can control the mit following an uncontrolled release of radioactivity. Additionally, the system provides temperature control for the control room during normal and post-accident operations. The control room emergency ventilation tem is comprised of the control room emergency air filtration system and a temperature control system. The control room emergency air filtration system consists oftwo redundant systems that recirculate and filter the control room air. Each control room emergency air filtration system consists of a moisture separato, electric heater, prefilter, upstream high efficiency particulate air (HEPA) filter, charcoal adsorber, downstream HEPA filter, and fin Additionally, ductwork, valves or dampers, and instrumentation form part of the system. Nxnnal Dpeion A portion of the control room emergency ventilation system is required to operate during normal operations to ensure the temperature of the control room is maintained at or below 95F. MILLSTONE - U1T 3 B 3/4 7-10 Amendment No.449,46,444, 24,

LBDCR 05-MP3-003-April 1,2005 KLANT SYSTEMS BASES 3/4.7.7- CONTROL ROOM EMERGENCY VIENRATION SYSTEM (Continued) BACKGROUND (Continued) PostAcident Opemtion The control room emergency ventilation system is required to operate during post-accident operations to ensure the temperature offhe cotrol rom is maintained and to ensure the control room ll remainhabitable dring and following accident conditions. ITe following sequence of events occurs upon receipt of a control building isolation (CBD signal or a signal indicating high radiation in the air supply duct to the control room envelope.

1. The control room boundary is isolated to prevent outside air from entering the control room to prevent the operators from being exposed to the radiological conditions that may exist outside the control room. The analsis for a loss ofcoolant accident assumes that the highest releases occur in the first hour ater a loss of coolant accident.

2. After 60 seconds, the control room envelope pressurizes to 118 inch water gauge by the control room emergency pressurization sstem. This action provides a continuous PURGE of the control room envelope d prevents inleakage from te outside eznvironmeL Technical Specification 3/4.7.8 provides the requirements for the control room envelope pressmization system.

3. Control room pressurization continues for the first hour.

4. After one hour, the control room emerpncy ventilation system will be placed in service in the filtered pressurization mode (outside air is diverted through the filters to the control room envelope to maintain a positive pressure). To rn the control room emergency air filtration system in the filtered pressuration mode, the air spply line must be manually opened.

APPLICAL SAFETY ANALYMS The OPERABIT of tde Control Room Emergency Ventilation System ensures that (1)the ambient ar temperature does not exceed the allowable temperature forcontinuous-duty rating for the eq iment and instrunentation cooled by this system, and (2)the control room will remamn habita e for oerations personnel during and followig all credible accident conditions. The OPERAB I ofthiB system in conjunction with control room design provisions is based on limiting the radiation exposure to personnel occupg the control rop. For all postulated desigUbasis accidents except a Fuel Haxdling Accident, the radiation exposure to personnel occupying th control room sshall be 5rem orless whole body, or its equivalent for the duration of theaccident, consistentwithterequirements of General Design CitErion 19 of Appendix "A," 10 CFR 50. Por a Fuel Handling Accident, thie radiation exposure to personnel ccu g the control room "hallbe 5 rem TEDE or less, consistent wit te rements of 10 CER 50.67. This limitation is consistent withe ru ents of GeneralDesign Criterion 19 ofAppendix A, IO CFR Part 50. MIELSTONE- UNIT 3 B 314 7-11 Amendment No. 46, , Bhala May frg5-

LBDCR No. 04-MP3-015 February 24, 2005 PLANT SYSTEMS BASES 3k4.7.7 CONTROL ROOM EMERGENCY VENT7LA70N-SYSTEM (Continued LlhM M-NGCONDMTON FOR OPERATIO Two independent control room cmergency air filtration systems are rquired to be OPERABLE to ensure that at least one is available in the event the other system is disabled. A control room emergency air filtration system is OPERABLE when the associated: a Fan is OPERABLE;

b. HEMA filters and charcoal adsorbers are not excessively restricting flow and are capable of performing their filtration functions; and C. moisture separator, heater, ductwork, valves, and dampers are OPERABLE, and air circulation can be maintained.

The Integrity of the control room habitability boundary (i.e, walls, floors, ceilings, ductwork, and access doors) must be maintained such that the control building habitability zone can be maintained at its design positive pressure if required to be aligned in the filtration pressurization mode. However, the LCO is modified by a footnote allowing the control room boundary to be opened intermittently under administrative controls. For entry and exit through doors the admiistrative control of the opening is performed by the person(s) entering or exiting the area For other openings, these controls consist of stationing a dedicated individual at the opening who is Inconstant communication with the control room. This individual will have a method to rapidly close the opening when a need for control room isolation is indicated. APPLICABIM In MODES 1, 2, 3,4, 5, and 6. During fuel movement within containment or the spent fuel pool. ACTIONS a., b., and c. of this specification are applicable at all times during plant operation InMODES 1,2,3, and 4. ACI7ONS d. and e. are applicable InMODES Sand 6, and whenever fuel Isbeing moved within containment or the spent fuel pool. The fuel handling accident analyses assume that during a fuel handling accident some of the fuel that is dropped and some of the fuel impacted upon is damaged. Therefore, the movement of either new or irradiated fuel (assemblies or individual fuel rods) can cause a fuel handling accident and this specification is applicable whenever new or irradiated fuel is moved within the containment or the storage pool. MILLSTONE - UNIT 3 B 314 7-12 Amendment No. 4a6, ,249,

                                                       /3ciw Chax& 66 8-65-- OC6-S

IBDCR No. 04-MP3-0lS February 24, 2005 PLANTSYSTfEMS BASES 314.7.7 CONTROL ROOM EMERGENCY VENT1AT17 SYSTEM (Continued) MODES 1.2.3. and 4

a. With one control room emergency air filtration system inoperable, action must be taken to restore the inoperable system to an OPERABLE status within 7 days. In this condition, the remaining control room emergency air filtration system is adequate to perform the control room protection function. However, the overall reliability is reduced because a single failure in the OPERABLE train could result in a loss of the control room emergency air filtration system function. The 7-day completion time is based on the low probability of a DBA occurring during thds time period, and the ability of the remaining train to provide the required capability.

If the inoperable train cannot be restored to an OPERABLE status within 7 days, the unit must be placed in at least HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />. These completion times are reasonable, based on operating experience, to reach the required unit condition from fill power conditions in an orderly manner and without challenging unit systems.

b. With both control room emergency air filtration systems inoperable, except due to an

      *inoperable control room boundaMr the movement of fuel within the spent fael pool must be immediately suspended. At least one control room emergency air filtration system must be restored to OPERABLE status within 1 hour, or the unit must be in HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUIDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />. These completion times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

c. With both control room emergency air filtration systems inoperable due to an inoperable control room boundaMy, the movement offuel within the spent fuel pool must be immediately suspended The control room boundary must be restored to OPERABLE status within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br />, or the unit must be in HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUIDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

If the control room boundary Is inoperable in MODES 1, 2, 3, and 4, the control room emergency air filtration systems cannot perform their intended functions. Actions must be taken to restore an OPERABLE control room boundary within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br />. During the period that the control room boundary is inoperable, appropriate compensatory measures (consistent with the intent ofGDC 19) should be utilized to protect control room operators from potential hanrds such as radioactive contamination toxic chemicals, smoke, temperature and relative humidity, and physical security. Preplanned measures should be MILLSTONE - UNIT 3 B 314 7-13 Amendment No. 46, 0a, 249

                                                 &,,b Ma'f                           -SSS~

LBDCR No. 04-MP3-015 February 24, 2005 PLANT-SYSTEMS BASES 3/4.7.7 Q RM ROOMEMERGENCY 3MLAT N SlfSTEM (Continued) ACONS (Continued) available to address these concerns for intentional and unintentional ently in to this condition. The 24 hour allowed outage time is reasonable based on the low probability of a DBA occuxring during this time riod, and the use of compensatory measures. The 24 hour allowed outage time is a typically reasonable time to diagnose, plan, and possibly repair, and test most problems with the control room boundary. MODES 5 and 6. and fuel movement within containment or the spent fuel pool

d. With one control room emergency air filtration system in perable, action must be taken to restore the inoperable system to an OPERABLE status wfthin 7 days. After 7 days, either initiate and maintain operation of the remaining OPERABLE control room emergency air filtration stm in the recirculation mode or suspend the movement of fuel. Initiating sndm ntaitg oeraionofthe OPERABLE trai in the recirculation mode ensures:

          ) OPERABII of the train will not bco               md by a filure of the automatic
       -actuationlogic; and ii) active failures will be readily detected.

e. With both control room emergency airfiltration systems inoperable, or with the tain required by ACIION d' not capable of beig powered by an OPERABLE emergency power source, actions must be tiken to spend all op ions Involving the movement of uellThis acton places the unit ina minimizes risk. This action does not preclude the movement af fult to a safe position.

SURVEILLANCE REQUIREME S 4.7.7.a The control room environment should be checked criodically to that the control tnsure rom temperature control system is fimctioning properly. Verifyiat the control room air temperature is less than or equal to 950F at least once per 12 hou is sufficient It Isnot necessary to cycle the control room ventilation chillers. The control room is manned durg operations covered by the technical specifications. Typically, temperature abeations will be readily apent. 4.7,W.b Standby systems should be checked perodicaly to ensure that they fiuction properly. As the environment and normal operating conditions on this system are not too severe, testing the trains once every 31 days on a STAGGERED TEST BASIS provides an adequate check of this ytem. This surveillance requirement verifies a system flow rate of 1,120 cfmn : 20%. 2 ditionally, the system is required to opueate for at least 10 continuous hours with the heaters enerized. These operations are sufficient to reduce the buildup of moisture on the adsorbers and HEP filters dueto the humidity in the ambient air. MLLSTONE-UNT 3 B 314 7-13a Amendment No. 4*6, 1 20%,24,

                                                        '46O&O        of                      - Cfi -;, d

BASES ,:'.7., CONWOL POOM EMERGEN! FT I-'-- 0;:l EM - SURVEILLANCE REQUIREMENTS (Continued) Thep--, ai-efficienc/. -1ni rriifi ,rat-charcoal The frequencJ i, - - n l r an; structural fraintenance on th - - - h:s (2) following painting, fire, or che-mcal Wi ave in An;,y nt1lt)io Zorh communicating with the system. ANSI N510-1980 will be used as a procedural guide for curv eilIance testina. 4.7.7.c. 1 This surveillance verifies that the svstem satisfies the in-place penetration and bypass leakage testing acceptance criterion of less than 0.05: 10 accordance with Regulatory Position C.5.a, C.5.c. and C.5.d of Regulatory Guide 1.52. Revision 2, March 1978, while operating the system at a flow rate of 1,120 cfm +/- 20%'. ANSI NJ510-1980 is used in lieu of ANSI N510-1975 referenced rn the regulatory guide. 4.7.7.c.2 This surveillance requires that a representative carbcor sample be obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978 and that a laboratory analysis verify that the representative :arbon sample meets the laboratory testing criteria of ASTM D3803-89 and Millstone Unit 3 specific parameters. The laboratory analysis is required to be performed within 31 days after removal of the sample. ANSI N510-1980 is used in lieu of ANSI N1510-1975 referenced in Revision 2 of Regulatory Guide 1.52. 4.7.7.c.3 This surveillance verifies that a system flow rate of 1,120 cfm +/- 20C., during system operation when testing in accordance with ANSI N510-1980. 4.7.7.d After 720 hours30 days <br />4.286 weeks <br />0.986 months <br /> of charcoal adsorber operation, a representative carbon sample must be obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, and a laboratory analysis must verify that the representative carbon sample meets the laboratory testing criteria of ASTM D3803-89 and Millstone Unit 3 specific parameters. MILLSTONE - UNIT 3 B 3/4 7-14 Amendment No. NOd Add, 206 0867

PLANT SYSTEMS BASES 3/4.7.7 CONTROL ROOM EMERGENCY VENTILATION SYSTEM (Continued) SURVEILLANCE REQUIREMENTS (Continued) The laboratory analysis is required to be performed within 31 days after removal of the sample. ANSI N510-1980 is used in lieu of ANSI N510-1975 referenced in Revision 2 of Regulatory Guide 1.52. The maximum surveillance interval is 900 hours37.5 days <br />5.357 weeks <br />1.233 months <br />, per Surveillance Requirement 4.0.2. The 720 hours30 days <br />4.286 weeks <br />0.986 months <br /> of operation requirement originates from Nuclear Regulatory Guide 1.52, Table 2, Note C. This testing ensures that the charcoal adsorbency capacity has not degraded below acceptable limits as well as providing trending data. 4.7.7.e.1 This surveillance verifies that the pressure drop across the combined HEPA filters and charcoal adsorbers banks at less than 6.75 inches water gauge when the system is operated at a flow rate of 1,120 cfm + 20%. The frequency is at least once per 24 months. 4.7.7.e.2 This surveillance verifies that the system maintains the control room at a positive pressure of greater than or equal to 1/8 inch water gauge at less than or equal to a pressurization flow of 230 cfm relative to adjacent areas and outside atmosphere during positive pressure system operation. The frequency is at least once per 24 months. The intent of this surveillance is to verify the ability of the control room emergency air filtration system to maintain a positive pressure while running in the filtered pressurization mode. MILLSTONE - UNIT 3 B 3/4 7-15 Amendment No. Aft, ,1X. J#, Z 206 0934

LBDCR 05-MP3-003 April 1, 2005 PLANT SYSTEMS BASES 3/4.7,7 CON1ROJ ROOM ENEROM~h A TION SYSTEM (Continued) SURVEJLLAN REOUIREMENM (Continued) During the first hour, the control room pressurization system creates and maintains the positive pressure in the control room. This capability is verified by Surveillance Requirement 4.7.8.C, independent of Surveillance Requirement 4.7.7.e.2. A CBI signal will automatically align an operating filtration system into the recirculation mode of operation due to the isolation of the airsupply line to the filter. After the first hou of an event with the potential for a radiological release, the control room emergency ventilation system will be aligned in the filtered prsstion mode (outside air is diverted through the filters to the control room envelope to maintain a positive pressure). Alignment to the filtered pressurization mode requires manual operator action to open the air I Wpply line. This surveillance verifies that the heaters can dissipate 9.4 : I kW at 480V when tested in accordancewith ANSINSO-1980. he frequenyis atlcast onceper24 montfs. The heaterkW mcasured must be corrected to its nameplate rating. Variations in system voltage can lead to m aeents ofkW which cannot be compared to the nameplate rating because the output kW is proportional to the square ofthe voltage. 4.7f Following the complete or partial replacement of a IMPA filter bank, the OPERABITsY of the cleanup system should be confirmed. This is accomplished by verifyn that the cleanup system satisfies the In-place penetration and bypass leaage testing acceptance criterion ofless than 0.05% in accordance with ANSI NS IO-1980 for a DOP test aerosol while operating the system at a flow rate of 1,120 cfind: 20%. l}ffZSTONE - UN1T 3 B 3/4 7-16 Amendment No. 46, M,, £6, 23Ck~o qwe/3G 1f S- t5~-- 2

LBDCR No. 04-M3-01 5 February24, 2005 PLANT SYSTES BASES 3/4.7.7- _C: 1 RO OM EMERG}ENCY VENAT ON -SYSTrEM (Continued) SURVEILLANCE BEOIRE OME(Continued) 43.7.g Following the complete or partW Pacement of a charcoal adsorber bank the OPERABIIX1Y of the cleanup system sh be confirmed. This is accomplished by verifying that the cleanup system satsfed the inplac penetration and byass lealks testing acceptance criterion of less than 0.05% inaccordancewiihANSIN510-1980 forahialogenatedhydrocarbon refirigerant test gas while operating the system at a flow of 1,120 cfin 20°Kd

References:

(I) Nuclear Regulatory Guide 1.52, Revision 2 (2) MP3 UFSAR,lTble 1.S-1,NRCRegulatoyGuide 1.52 (3) NRC GenenicLetter9l-04 (4) Condition Report (CR) #M3-99-0271 314.7.8-CONTROL ROOM ENEL PR ~ESSURIZATIOW SYSTEM BACKGROIMN The control room envelope pressurization system provides a protected environment from which operators can control the unit following an uncontrolled release of radioactivity. The control room envelope pressurization stem consists oftwo banks of air bottles with its associated piping instiumentation, and controls. Each bank is capable ofprovdng the control room area with one-hour of air following any event with the potential for radioactive releases. Control Room Envelope OPERABILTTY is satisfied while:

• Door 352 (C-49-1) is closed (East door)
• Door 351 (C-47-I) is closed, butC-47-1A, ATDM issile Shield, is ntclosed (West doors)

Womnal OaMtion During normal operations, the control room envelope pressurization system is required to be on standby. Post Accident Ooeration The control room envelope pressurization ytem is required to operateduring post-accident operations to ensure the control room will remain haitable during and following accident conditions. The sequence of events which occurs uon receipt of a control building isolation (CBI signal or a signal indicating high radiation In tHe air supply duct to the control room envelope is descnbed in Bases Section 314.7.7. MILLSTONE-UNIT3 B 3/4 7-17 AmendmentNo.4-6, 4a-ZOL #Cavl Pf aigoJe

LBDCRNo. 04-MP3-015 February24,2005 PLANT SYSTEMS BASES 314.7.8 CONTROLROOM BFLOE PRESSURIZA710N SYSTEM (Continued) APPLICABLE SAFEY ANALYSTS The OPERABILITY of the control room envelope pressurization system ensures that: (1) breathable air is supplied to the control room, instrumentation rack room, and computer room, and (2) a positive pressure is created and maintained within the control room envelope during control building isolation for the first hour following any event with the potential for radioactive releases. Each system is capable ofproviding an adequate air supply to the control room for one hour following an initiation of a control building isolation signal. After one hour, operation ofthe control room emergency ventilation system would be initiated. L1MIM1hN COND-TION FOR OPERATION Two independent control room envelope pressurization systems are required to be OPERABLE to ensure that at least one is available in the event the other system is disabled. I A control room envelope pressurization system is OPERABLE when the associated:

a. air storage bottles are OPERABLE; and

b. piping and valves are OPERABLE.

The integrity of the control room habitability boundary (i.e., wails, floors, ceilings, ductwqrk, and access doors) must be maintained. However, the LCO is modified by a footnote allowing the control room boundary to be opened Intermittently under administrative controls. For entry and exit throuigh doors the adminstative control of the opening is perfomed by the person(s) enterig or exiting the area For other openings, these controls consist of stationing a dedicated individual at the opening who is in constant communication with the control room. This individual will have a method to rapidly ciose the opening when a need for control room isolation is indicated. MILLSTONE - UNIT 3 B 3/4 7-11 Amendment No. *6, , .9, 4aeI V1k"I &y jfl & 6p-cf3) C

LBDCR No. 04MP3-015 February 24, 2005 ELAXE SYSTSMS BASES. 314.7.8 CONTROL ROOM ENVELOPE PRESSURIZATION SYSTEM (Continued) APPLICABILnTY In MODES 1,2,3,4,5 and 6. During fuel movement within containment or the spent fuel pool. ACTIONS a., b., c., and d. of this specification are applicable at all times during plant operation I in MODES 1, 2,3, and 4.. ACTIONS c. and £ are applicable in MODES 5 and 6, and whenever fuel is being moved within containment or the pent fuel pool. The fuel handling accident analyses assume that during a fuel handling accident some of the fuel that is dropped and come of the fuel that is impacted upon is damaged. Therefore, the movement of either new or irradiated fuel (assemblies or individual fuel rods) can cause a fuel handling accidentd and this specification is applicable whenever new or irradiated fuel is moved within the containment or the storage pool. AgCIONS MODES 1,2, 3, and 4

a. With one control room envelope pressurization system inoperable, action must be taken either to restore the inoperable system to an OPERABLE status within 7 days, orplace the unit in HOT STANDBY within six hours and COLD SHUTDOWN within the next 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

The remaining control room envelope pressurization system is adequate to perform the control room protection firnction. However, the overall reliability is reduced because a single failure in the OPERABLE train could result in a loss of the control room envelope pressurization system. The 7-day completion time is based on the low probability of a design basis accident occurring during this time period and the ability ofthe remaining train to provide the required capability. The completion times for the unit to be placed in HOT STANDBY and COLD SHUTDOWN are reasonable. They are based on operating experience, and they permit the unit to be placed in the required conditions from full power conditions in an orderly manner and without challenging it systems.

b. With both control room envelope pressurization systems inoperable, except due to an inoperable control room boundary or during performance of Surveillance Requirement 4.7.8.c, the movement of fuel within the spent fuel pool must be immediately suspeaded.

At least one control room envelope prsurization system must be restored to OPERABLE status within I hour, or the unit must be in HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />. These completion times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems MLLLSTONE-UNIT3 B 3/4 7-19 Amendment No. 4-6,,20a, ;9,

                                                  '60o2          QAfv              J    -   dS-

PLANT SYSTEMS BASES 3/4.7.8 CONTROL ROOM ENVELOPE PRESSURIZATION SYSTEM (Continued) ACTIONS (Continued)

c. With both control room envelope pressurization systems inoperable due to an inoperable control room boundary, the movement of fuel within the spent fuel pool must be immediately suspended. The control room boundary must be restored to OPERABLE status within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br />, or the unit must be in HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />.

If the control room boundary is inoperable in MODES 1, 2, 3, and 4, the control room envelope pressurization systems cannot perform their intended functions. Actions must be taken to restore an OPERABLE control room boundary within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br />. During the period that the control room boundary is inoperable, appropriate compensatory measures (consistent with the intent of GDC 19) should be utilized to protect control room operators from potential hazards such as radioactive contamination, toxic chemicals, smoke, temperature and relative humidity, and physical security. Preplanned measures should be available to address these concerns for intentional and unintentional entry in to this condition. The 24 hour allowed outage time is reasonable based on the low probability of a DBA occurring during this time period, and the use of compensatory measures. The 24 hour allowed outage time is a typically reasonable time to diagnose, plan, and possibly repair, and test most problems with the control room boundary.

d. With both control room envelope pressurization systems inoperable during the performance of Surveillance Requirement 4.7.8.c and the system not being tested under administrative control, the movement of fuel within the spent fuel pool must be immediately suspended. At least one control room envelope pressurization system must be restored to OPERABLE status within 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />, or the unit must be in HOT STANDBY within the next 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and in COLD SHUTDOWN within the following 30 hours1.25 days <br />0.179 weeks <br />0.0411 months <br />. The administrative controls for the system not being tested consist of a dedicated operator, in constant communication with the control room, who can rapidly restore this system to OPERABLE status. Allowing both control room envelope pressurization systems to be inoperable for 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> under administrative control is acceptable since the system not being tested is inoperable only because it is isolated. Therefore, the system can be rapidly restored if needed. The other completion times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

MILLSTONE - UNIT 3 B 3/4 7-20 Amendment No. 136, 4 203, 219

PLANT SYSTEMS BASES 314.7.8 CONTROL ROOM ENVELOPE PRESSURIZATION SYSTEM (Continued) ACTIONS (Continued) MODES 5 and 6. and fuel movement within containment or the spent fuel pool

e. With one control room envelope pressurization system inoperable, action must be taken to restore the inoperable system to an OPERABLE status within 7 days. After 7 days, immediately suspend the movement of fuel. This action places the unit in a condition that minimizes potential radiological exposure to Control Room personnel. This action does not preclude the movement of fuel to a safe position.

The remaining control room envelope pressurization system is adequate to perform the control room protection function. However, the overall reliability is reduced because a single failure in the OPERABLE train could result in a loss of the control room envelope pressurization system. The 7-day completion time is based on the low probability of a design basis accident occurring during this time period and the ability of the remaining train to provide the required capability. Stud tensioning may continue in MODE 6 and a MODE change to MODE 5 is permitted with a control room envelope pressurization system inoperable (Reference 1).

f. With both control room envelope pressurization systems inoperable, immediately suspend the movement of fuel. This action places the unit in a condition that minimizes potential radiological exposure to Control Room personnel. This action does not preclude the movement of fuel to a safe position.

SURVEILLANCE REOUIREMENTS 4.7.8.a This surveillance requires verification that the air bottles are properly pressurized. Verifying that the air bottles are pressurized to greater than or equal to 2200 psig will ensure that a control room envelope pressurization system will be capable of supplying the required flow rate. The frequency of the surveillance is at least once per 7 days. It is based on engineering judgment and has been shown to be appropriate through operating experience. 4.7.8.b This surveillance requires verification of the correct position of each valve (manual, power operated, or automatic) in the control room envelope pressurization system flow path. It helps ensure that the control room envelope pressurization system is capable of performing its intended safety function by verifying that an appropriate flow path will exist. The surveillance applies to those valves that could be mispositioned. This surveillance does not apply to valves that have been locked, sealed, or secured in position, because these positions are verified prior to locking, sealing, or securing. The frequency of the surveillance is at least once per 31 days on a STAGGERED TEST BASIS. It is based on engineering judgment and has been shown to be appropriate through operating experience. MILLSTONE - UNIT 3 B 3/4 7-20a Amendment No. 6, 181, 20, 219

PLANT SYSTEMS BASES 3/4.7.8 CONTROL ROOM ENVELOPE PRESSURIZATION SYSTEM (Continued) SURVEILLANCE REQUIREMENTS (Continued) 4.7.8.c The performance of the control room envelope pressurization system should be checked periodically. The frequency is at least once per 24 months and following any major alteration of the control room envelope pressure boundary. A major alteration is a change to the control room envelope pressure boundary that: (1) results in a breach greater than analyzed for acceptable pressurization and requires nonroutine work evolutions to restore the boundary. A nonroutine work evolution is one which makes it difficult to determine As-Found and As-Left conditions. Examples of routine work evolution include: (1) opening and closing a door, and (2) repairing cable and pipe penetrations because the repairs are conducted in accordance with procedures and are verified via inspections. For these two examples, there is a high level of assurance that the boundary is restored to the As-Found condition. This surveillance requires at least once per 24 months or following a major alteration of the control room envelope pressure boundary by:

• Verifying the control room envelope is isolated in response to a Control Building Isolation Test signal,
• Verifying, after a 60 second time delay following a Control Building Isolation Test signal, the control room envelope pressurizes to greater than or equal to 0.125 inch water gauge relative to adjacent areas and outside atmosphere; and
• Verifying the positive pressure of Technical Specification 4.7.8.c.2 is maintained for greater than or equal to 60 minutes.

Changes in conditions outside the control room envelope cause pressure spikes which are reflected on the differential pressure indicator, 3HVC-PDI 113. Pressure spikes or fluctuations which result in the differential pressure momentarily dropped below the 0.125 inch water gauge acceptance criteria are acceptable providing the following conditions are met:

1. Differential pressure remains positive at all times.

2. Differential pressure is only transitorily below the acceptance criteria.

3. Differential pressure returns to a value above the acceptance criteria.

MILLSTONE - UNIT 3 B 3/4 7-21 Amendment No. 17f, 701, 206 0935

PLANT SYSTEMS BASES 3/4.7.8 CONTROL ROOM ENVELOPE PRESSURIZATION SYSTEM (Continued) SURVEILLANCE REQUIREMENTS (Continued) The control room envelope pressurization system design basis criteria is set at a 0.125 inch water gauge criteria to account for wind effects, thermal column effects, and barometric pressure changes. Pressurizing the control room envelope of 0.125 inch water gauge above the initial atmospheric pressure ensures it will remain at a positive pressure during subsequent changes in outside conditions over the next 60 minutes. Since the surveillance requirement is verified by actual reference to outside pressure, allowances are provided for differential pressure fluctuations caused by external forces. The 0.125 inch water gauge acceptance criteria provides the margin for these fluctuations. This meets the requirements of Regulatory Guide 1.78 and NUREG-800, Section 6.4 and is consistent with the assumptions in the Control Room Operator DBA dose calculation. 4.7.8.c.1 This surveillance verifies that the control room envelope is isolated following a control building isolation (CBI) test signal. 4.7.8.c.2 This surveillance verifies that the control room envelope pressurizes to greater than or equal to 1/8 inch water gauge, relative to the outside atmosphere, after 60 seconds following receipt of a CBI test signal. 4.7.8.c.3 This surveillance verifies that the positive pressure developed in accordance with Surveillance Requirement 4.7.8.c.2 is maintained for greater than or equal to 60 minutes. This capability is independent from the requirements regarding the control room emergency filtration system contained in Technical Specification 3/4.7.7. Also, following the first hour, the control room emergency ventilation system is responsible for ensuring that the control room envelope remains habitable.

References:

(1) NRC Routine Inspection Report 50-423/87-33, dated February 10, 1988. (2) NRC Generic Letter 91-04. MILLSTONE - UNIT 3 B 3/4 7-22 Amendment No. 136 0609

PLANT SYSTEMS LBDCR 3-17-01 February 14, 2002 BASES-3/4.7.9 AUXILIARY BUILDING FILTER SYSTEM The OPERABILITY of the Auxiliary Building Filter System ensures that radioactive materials leaking from the equipment within the charging pump, component cooling water pump and heat exchanger areas following a LOCA are filtered prior to reaching the environment. The charging pump/reactor plant component cooling water pump ventilation system must be operational to ensure operability of the auxiliary building filter system and the supplementary leak collection and release system. Operation of the system with the heaters operating for at least 10 continuous hours in a 31-day period is sufficient to reduce the buildup of moisture on the adsorbers and HEPA filters. The operation of this system and the resultant effect on offsite dosage calculations was assumed in the safety analyses. ANSI N510-1980 will be used as a procedural guide for surveillance testing. Laboratory testing of methyl iodide penetration shall be performed in accordance with ASTM D3803-89 and Millstone Unit 3 specific parameters. The heater kW measured must be corrected to its nameplate rating. Variations in system voltage can lead to measurements of kW which cannot be compared to the nameplate rating because the output kW is proportional to the square of the voltage. LCO 3.7.9 Action Statement: With one Auxiliary Building Filter System inoperable, restoration to OPERABLE status within 7 days is required. The 7 days restoration time requirement is based on the following: The risk contribution is less for an inoperable Auxiliary Building Filter System, than for the charging pump or reactor plant component cooling water (RPCCW) systems, which have a 72 hour restoration time requirement. The Auxiliary Buildir- Filter 1-stem is not a direct support system for the charging pumps or RPCCW pumps. Because the pump area is a common area, and as long as the other train of the Auxiliary Building Filter System remains OPERABLE, the 7 day restoration time limit is acceptable based on the low probability of a DBA occurring during the time period and the ability of the remaining train to provide the required capability. A concurrent failure of both trains would require entry into LCO 3.0.3 due to the loss of functional capability. The Auxiliary Building Filter System does support the Supplementary Leak Collection and Release System (SLCRS) and the LCO Action statement time of 7 days is consistent with that specified for SLCRS (See LCO 3.6.6.1). Surveillance Requirement 4.7.9.c Surveillance requirement 4.7.9.c requires that after 720 hours30 days <br />4.286 weeks <br />0.986 months <br /> of operation a charcoal sample must be taken and the sample must be analyzed within 31 days after removal. The 720 hours30 days <br />4.286 weeks <br />0.986 months <br /> of operation requirement originates from Regulatory Guide 1.52, Revision 2, March 1978, Table 2, Note "c", which states that "Testing should be performed (1) initially, (2) at least once per 18 months thereafter for systems maintained in a standby status or after 720 hours30 days <br />4.286 weeks <br />0.986 months <br /> of system operations, and (3) following painting, fire, or chemical release in any ventilation zone communicating with the system." This testing ensures that the charcoal adsorbency capacity has not degraded below acceptable limits as well as providing MILLSTONE - UNIT 3 B 3/4 7-23 Amendment No. p7, }}i, M, 709, 0895 "Revised April 2, 2002" Ac Xffv W

PLANT SYSTEMS BASES 3/4.7.9 AUXILIARY BUILDING FILTER SYSTEM The OPERABILITY of the Auxiliary Building Filter System, and associated filters and fans, ensures that radioactive materials leaking from the equipment within the charging pump, component cooling water pump and heat exchanger areas following a LOCA are filtered prior to reaching the environment. Operation of the system with the heaters operating for at least 10 continuous hours in a 31-day period is sufficient to reduce the buildup of moisture on the adsorbers and HEPA filters. The operation of this system and the resultant effect on offsite dosage calculations was assumed in the safety analyses. ANSI N510-1980 will be used as a procedural guide for surveillance testing. Laboratory testing of methyl iodide penetration shall be performed in accordance with ASTM D3803-89 and Millstone Unit 3 specific parameters. The heater kW measured must be corrected to its nameplate rating. Variations in system voltage can lead to measurements of kW which cannot be compared to the nameplate rating because the output kW is proportional to the square of the voltage. The Charging Pump/Reactor Plant Component Cooling Water Pump Ventilation System is required to be available to support the Auxiliary Building Filter System and the Supplementary Leak Collection and Release System (SLCRS). The Charging Pump/Reactor Plant Component Cooling Water Pump Ventilation System consists of two redundant trains, each capable of providing 100% of the required flow. Each train has a two position, "Off" and "Auto," remote control switch. With the remote control switches for each train in the "Auto" position, the system is capable of automatically transferring operation to the redundant train in the event of a low flow condition in the operating train. The associated fans do not receive any safety related automatic start signals (e.g. Safety Injection Signal). Placing the remote control switch for a Charging Pump/Reactor Plant Component Cooling Water Pump Ventilation Train in the "Off" position to start the redundant train or to perform post maintenance testing to verify availability of the redundant train will not affect the availability of that train, provided appropriate administrative controls have been established to ensure the remote control switch is immediately returned to the "Auto" position after the completion of the specified activities or in response to plant conditions. These administrative controls include the use of an approved procedure and a designated individual at the control switch for the respective Charging Pump/Reactor Plant Component Cooling Water Pump Ventilation Train who can rapidly respond to instructions from procedures, or control room personnel, based on plant conditions. 3/4.7.10 SNUBBERS All snubbers are required OPERABLE to ensure that the structural integrity of the Reactor Coolant System and all other safety-related systems is main-tained during and following a seismic or other event initiating dynamic loads. For the purpose of declaring the affected system OPERABLE with the inoperable snubber(s), an engineering evaluation may be performed, in accordance with Section 50.59 of 10 CFR Part 50. MILLSTONE - UNIT 3 B 3/4 7-23 Amendment No. F7, 777, 711,203 0840 Ad

LBDCR No. 04-MP3-015 February 24, 2005 PLANT SYSTEMS BASES LCO 3.7.9 ACTION statement. With one Auxiliary Building Filter System inoperable, restoration to OPERABLE status within 7 days is required. The 7 days restoration time requirement is based on the following: The risk contribution is less for an inoperable Auxiliary Building Filter System, than for the charging pump or reactor plant component cooling water (RPCCW) systems, which have a 72 hour restoration time requirement. The Awdliazy Building Filter System is not a direct support system for the charging pumps or RPCCW pumps. Because the pump area is a common area, and as long as the other train ofthe Auxiliary Building Filter System remains OPERABLE, the 7 day restoration time limit is acceptable based on the low probability of a DBA occurring during the time period and the ability of th remaining train to provide the required capability. A concurrent failure of both tains would require entry into LCO 3.0.3 due to the loss of fimctional capability. The Anxiliary Building Filter System does support the Supplementary Leak Collection and Release System (SLCRS) and the LCO ACTION statement time of 7 days Is consistent with that specified for SLCRS (See LCO 3.6.6.1). Surveillance Requirement 4.7.9.c Surveillance requirement 4.7.9.c requires that after 720 hours30 days <br />4.286 weeks <br />0.986 months <br /> of operation a charcoal sample must be taken and the sample must be analyzed within 31 days after removal. The 720 hours30 days <br />4.286 weeks <br />0.986 months <br /> of operation requirement originates from Regulatory Guide 1.52, Revision 2, March 1978, TIble 2, Note lc", which gtates that £rcsting should be performed (1) initially, (2) at least once per 18 months thereafter for systems maintained in a standby status or after 720 hours30 days <br />4.286 weeks <br />0.986 months <br /> of system operadions, and (3) following painting, fire, or hemical release in any ventilation zone commcating with the system." Tbis testing ensures that the charcoal adsoibency capacity has not degraded below acceptable limits as well as providing trending data. The 720 hour figure is an arbitrary number wich is equivalent to a 30 day period. This criteria is directed to filter systems that are normally in operation and also provide emergency air cleaning functions in the event of a Design Basis Accident. The applicable filter unit are normally in operation and sample canisters are typically removed due to the 18 month criteria. 314.7.10 SNUBBERS All snubbers are required OPERABLE to ensure that the structural integrity ofthe Reactor Coolant System and all other safety-related systems is maintained during and following a seismic or other event initiating dynamic loads. For the putpose of declaring the affected system OPERABLE with the inoperable snubber(s), an engineering evaluation may be performed, in accordance with Section 0.59 of 10 CFR Part 50. Snubbers are classified and gpe by design and manufacturer but not by size. Snubbers of the same manufacturer butg different internal mechanisms are classified as different types. For exampe, mechanical mnubbers utilizing the same design features of the 2-kip, lOkip and 100-kip capacity MILLSTONE - UNIT 3 B 314 7-23a Amendment No. &7,449,446,484,

                                            &g  Wi

PLANT SYSTEMS BASES 3/4.7.10 SNUBBERS (Continued) temperature, atmosphere, location, etc.), and the recommendations of Regulatory Guides 8.8 and 8.10. The addition or deletion of any hydraulic or mechanical snubber shall be made in accordance with Section 50.59 of 10 CFR Part 50. The visual inspection frequency is based upon maintaining a constant level of snubber protection to each safety-related system during an earthquake or severe transient. Therefore, the required inspection interval varies inversely with the observed snubber failures on a given system and is determined by the number of inoperable snubbers found during an inspection of each system. In order to establish the inspection frequency for each type of snubber on asafety-related system, it was assumed that the frequency of snubber failures and initiating events is constant with time and that the failure of any snubber on that system could cause the system to be unprotected and to result in failure during an assumed initiating event. Inspections performed before that interval has elapsed may be used as a new reference point to determine the next inspection. However, the results of such early inspections performed before the original required time interval has elapsed (nominal time less 25%) may not be used to lengthen the required inspection interval. Any inspection whose results require a shorter inspection interval will override the previous schedule. The acceptance criteria are to be used in the visual inspection to determine OPERABILITY of the snubbers. For example, if a fluid port of a hydraulic snubber is found to be uncovered, the snubber shall be declared inoperable and shall not be determined OPERABLE via functional testing. To provide assurance of snubber functional reliability, one of three functional testing methods is used with the stated acceptance criteria:

1. Functionally test 10% of a type of snubber with an additional 5%

tested for each functional testing failure, or

2. Functionally test a sample size and determine sample acceptance or rejection using Figure 4.7-1, or

3. Functionally test a representative sample size and determine sample acceptance or rejection using the stated equation.

Figure 4.7-1 was developed using 'Wald's Sequential Probability Ratio Plan' as described in 'Quality Control and Industrial Statistics' by Acheson J. Duncan. Permanent or other exemptions from the surveillance program for individual snubbers may be granted by the Commission if a Justifiable basis for exemption is presented and, if applicable, snubber life destructive testing was performed to qualify the snubbers for the applicable design conditions at either the com-pletion of their fabrication or at a subsequent date. Snubbers so exempted MILLSTONE - UNIT 3 B 3/4 7-24 Amendment Nos. If, F7, 7P,136 0609 PQ 1 0 1J7

PLANT SYSTEMS BASES 3/4.7.10 SNUBBERS (Continued) Figure 4.7-1 was developed using "Wald's Sequential Probability Ratio Plan" as described in "Quality Control and Industrial Statistics" by Acheson J. Duncan. Permanent or other exemptions from the surveillance program for individual snubbers may be granted by the Commission if a justifiable basis for exemption is presented and, if applicable, snubber life destructive testing was performed to qualify the snubbers for the applicable design conditions at either the com-pletion of their fabrication or at a subsequent date. Snubbers so exempted shall be listed in the list of individual snubbers indicatin the extent of the exemptions. The service life of a snubber is established via manufacturer input and information through consideration of the snubber service conditions and associated installation and maintenance records (newly installed snubbers, seal replaced, spring replaced, in high radiation area, in high temperature area, etc.). The requirement to monitor the snubber service life is included to ensure that the snubbers periodically undergo a performance evaluation in view of their age and operating conditions. These records will provide statistical bases for future consideration of snubber service life. 3/4.7.11 DELETED 3/4.7.14 AREA TEMPERATURE MONITORING The area temperature limitations ensure that safety-related equipment will not be subjected to temperatures in excess of their environmental qualification temperatures. Exposure to excessive temperatures may degrade equipment and can cause a loss of its OPERABILITY. The temperature limits include an allowance for instrument error of +2.20 F. MILLSTONE - UNIT 3 B 3/4 7-25 Amendment Nos. by, f2, j0o, Jfl, 0954 214 70W

LBDCR No. 04-MP3-015 February 24, 2005 314.8 ELECTRICALPOWER SYSTEMS BASES 3J4.8.1.3/4.8.2 and 3/4.8.3 A.C SOURCES. D.C. SOURCES. and ONS1TE POWER PJST1IBUlQ The OPERABILITY of em A.C. and D.C. powersources and associated distnbution systems during operation ensures that sufficient power will be available to supply the safety-reated equipment required for. (1) the safe shutdown of the facility, and (2) the mitigation and control of accident conditions within the facllity. The mininum specified independent and redundant A.C. and D.C. power sources and distribution systems satisfy the requiements of General Design Criterion 17 of Appendix A to 10 CFR Part 50. LCO 3.8.1.1 .a requires two independent offhite power sources. With both the RSST and the NSST available, either power source may supply power to the vital busses to meet the intent of Technical Specification 3.8.1.1.The FSAR, and Regulatory Guide 132,1.6, and 1.93 provide the basis for requirements concerning off-site power sources. The basic requirement is to have two independent of lite power sources. The requirement to have a fast transfer is W specifically stated. An automatic fast transfer is required for plants without a generator output trip breaker, here power from the NSST is lost on a turbine trip. The surveillance requirement for transfer from the normal circuit to the alternate circuit is required for a transfer from the NSST to the RSST in the event of an electrical failure. There is no specific requirement to have an automatic transfer from the RSST to the NSST. The ACMION requirements specified for the levels of degradation of the power sources provide restriction upon continued facility operation commensurate with the level of degradation. The OPERABILMTY of the power sources are consistent with the Initial condition assumptions of the safety analyses and are based upon maintaining at least one redundant set of onsite A.C. and D.C. power sources and associated distribution system OPERABLE during accident conditions coincident with an assumed loss-of-offsite power and single failure of the other onsite A.C. source. The A.C. and D.C. source allowable out-of-service times are based in part on Regulatozy Guide 1.93, "MAvalabiity of Electrical Power Sources " December 1974. Technical Specification 3.8.1.1 ACTTON Statements b.2 and c2 provide an allowance to avoid unnecessary testng of the other OPERABLE diesel generator. If it can be determied that the cause of the Inoperable diesel generator does not exist on the OPERABLE diesel generator, Surveillance Requirement 4.8.1 .12.aS does not have to be performed. If the cause of inoperability exists on the other OPERABLE diesel generator, the other OPERABLE diesel generator would be declared inoperable upon discovery, ACMION Statement c. would be entered, and appropriate actions will be taken, Once the failure is corrected, the common cause failure no longer exists, and the required ACIION Statements (b, c, and e.) will be satisfied. If it can not be determined that the cause of the inoperable diesel generator does not exist on the remaining diesel generator, performance of Surveillance Requirement 4.8.1.2 , within the allowed time period, suffices to provide assurance of continued OPERABILTY of the diesel generator If the inoperable diesel genator is restored to OPERABLE status prior to the determnation ofthe Ipact on the other diesel generator, evaluation will continue of the possible common cause failure. Tis continued evaluation is no MILSTONE - UNIT 3 B 314 8-1 Amendment No. 4

• B, 6a&io Ohetlr D'-Q*SC96

LBDCRNo. 04-MP3-015 FebruaSy 24,2005 314.8 LECCALPOWER SIMS BASES longer under the time constraint imposed while in ACMION Statements b.2 or c.2. The determination of the existence of a common cause failure that would affect the remaining diese generator will rquire an eevaluation of the current failure and the applicability to the an g diesel gcnerator. Examples that would not be a common cause fiflure include, but are not limited to:

1. Preplanned preventative maintenance or testing, or

2. An inoperable suort system with no potential common mode failure for the rmaing tdiesel gencrator, or

3. An independently testable component with no potential common mode failure for the rainig diesel generator.

When one diesel generator is inoperable, there is an additional ACIION requirement (b.3 and c3) to verify that all required systeras, subsystems, trains, components and devices, that depend on the remaining OPERABLE diesel generator as a source of emergency power, are also OPERABLE7 and ftat the steam-driven auxiliay feedwater pupm is OPERABLE. This requirement is intended to provide assurance that a loss-of-offsite power event will not result in a complete loss of safety fuiction of critical stems during the period one of the diesel generators is inopable. The ter verify, as used in this context means to administratively check by examng logs or other information to determine if certain components are out-of-service for aintenance or other reasons. It does not mean to perform the Sunreillance Requirements needed to demonstrate the OPERABILITY of the component. lf one Millstone Unit No. 3 diesel generator Is inoperable in MODES 1 through 4, a 72 hour allowed outage time is provided by ACTION Statement b.5 to allow restoration of the diesel generator, provided the requirements of ACIION Statements b.l, b.2, and b3 are met. This allowed outage time can be extended to 14 days If the additional reqirements contained in ACTION Statement b are also met. ACION Statement b.4 re rification that the Milstone Unit No.2 diesel geneators are OPERABLE as required by the plicable Millstone UnI No.2 Technical Specification (2diesel generatorsminMODES 1 hrough 4, and I diesel generator InMODES 5and 6) and the Millstone Unit No. 3 SBO diesel generator is available. The term verif, as used in this context, means to administratively check by examining logs or other information to determine if the required Millstone Unit No. 2 diesel generators and the Millstone Unit No. 3 SBO diesel generator are out of service for maintenance or other reasons. It does not mean to perform Surveillance Requiements needed to demonstrate the OPERABIL of the requitred Millstone Unit No. 2 diesel generators or availability of the Millstone Unit No. 3 SBO diesel generator. When using the 14 day allowed outage time provision and the Millstone Unit No. 2 diesel generatorequirements orMillstone UntNo. 3 SBQ diesel generator requirements are not met, 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> is allowed for restoration ofthe required Millstone Unit No.2 dese enerators and the Millstone Unit No. 3 SBO diesel generator. Ifany of the required Millstone Unit No. 2 diesel generators and/orMillstone Unit No. 3 SBO diesel generator ae not restored within 72 hours3 days <br />0.429 weeks <br />0.0986 months <br />, and one Millstone Unit No. 3 diesel generator is still inoperable, Millstone Unit No. 3 is required to shut down. MILLSTONE - UNIT 3 B 3/4 8-Ia Amendment No. 4#, MO,

                                                    ,d6a QAiyJ    Ylua           , f-

LBDCR No. 04-MP3-015 February 24,2005 314.8 ELECTRICAL POWER SYSTEMS BASES The 14 day allowed outage time for one inoperable Millstone Unit No. 3 diesel generator will allowperrc ofexteded diesel generator maintenance and repair activities (e.g, diesel ectons) wile the plant is operaing. To minime plant risk when usmg this extended allowed outage tme the followmg additional Millstone Unit No. 3 requirements must be met:

1) Te chargingpup andchargng p coolingpump inoperation shall be powered fom thebus not associated with tot of senice diesel generator. In addition, the spare charging pump will be available to replace an inservice charging pump if necessary.

2) The extended diesel generator outage shall not be scheduled when adverse or inclement weather conditions ador unstable grid conditions are predicted or present.

3) The availability of the Millstone Unit No. 3 SBO DG shall be verified by test performance within 30 days prior to allowing a Millstone Unit No. 3 EDO to be inoperable for greater than 72 hours3 days <br />0.429 weeks <br />0.0986 months <br />.

4) All activity in the switchyard shall be closely monitored and controlled. No elective maintenance within the switchyard that could challenge offlsite power availability shall be scheduled.

5) A contingency lan shall be available (OP 3314J, Auxiliary Building Emergency Ventilaton and t) to provide alternate room cooling to the chargiMm and CCP pump area (24'6" A lazyBulding) in the event of a faflure of the ventilation ystem prior to commencing an extended diesel generator outage.

In addition, the plant configuration shall be controlled during the diesel generator maintenance and repair activities to minimize plant risk consistent with the Configuration Risk Management Program, as required by 10 CFR 50.65(a)(4). The OPERABILITY of the minimum specifed A.C and D.C power sources and associated distribution ytems during shutdown and REFUELING ensures that: (1) the facility can be maintained in the shutdown or REFUELING condition for extended time periods, and (2) sufficient insttumentation and control capabft is available for monitoring and maintaining the unit status. The Surveillance Requirements for demonstrating the OPERABILIIY of the diesel generators are In accordance wih ffie recommendations of Reguatory Guides 1.9, 'Selection of Diese Generator Set Capacity for Standby Power Supplies," March 10, 1971; 1.108, Periodic Testinr of Diesel Generator Units Used as Onsite Electric Power Systems at Nuclear Power Plants Revision 1,August 1977; and 1.137, "Fuel-Oil Systems for Standby Diesel Generators," Revision 1,October 1979. LCO 3.8.1.1 ACTION statementeb.3 and c.3 Required ACION Statement b.3 and c3 requires that all stems, subsystems, trains, component, and devices that depend on the remainng OPERABLE diesel as a source of emergency power be verified OPERABLE. MILLSTONE - UNIT 3 B 314 8-lb Amendment No. 414, M, aa 9 C Af691, f - o-)5-S&S,

LBDCR No. 04-MP3-009 December 9,2004 314.8 ELECTRICAL POW SYSTEMS BASES 3/4.8.1.314.8.2. and 3L4.8.3 A.C. SOURCES. D.C SOURCES. AND ONSITE POWER DISTRIBllllON Technical Specification 3.8.1.1.b.1 requires each of the diesel generator day tanks contain a minimum volume of 278 gallons. Technical Specification 3.8.1 .2b. requires a minimum volume of 278 gallons be contained in the required diesel generator day tank. This capacity ensures that a minimum usable volume of 189 gallons is available. This volume permits operation ofthe diesel generators forapproximately27 minutes with the diesel generators loaded to the 2,000 hourrating of 5335 kw. Each diesel generator has two independent fuel oil transfer pumps. The shutoff level of each fuel oil transfer pump provides for approximately 60 minutes of diesel generator operation at the 2000 hour rating. The pumps start at day tank levels to ensure the m*inium level is maintained. The loss ofthe two redundant pimps would cause day tank level to drop below the minimum value. Technical Specification 3.8.1.b.2 requires a minimum volume of 32,760 gallons be contained in each of the diesel generator's fuel storage systems. Technical Specification 3.8.1.2h.2 requires a minimum volume of 32,760 gallons be contained in the required diesel generator's fuel storage system. This capacity ensures that a minimilm usable volume (29,180 gallons) is available to permit operation of each of the diesel generators for approximately three days with the diesel generators loaded to the 2,000 hourrating of 5335 kW. The ability to cross-tie the diesel generator fuel oil supply tanks ensures that one diesel generator may operate up to approximately six days. Additional fuel oil can be supplied to the site within twenty-four hours after contacting a fuel oil supplier. Su6refilance Requirements 4.8.1.1 .2.a.6 (montMhl) and 4.8.1.1 .2hb.2 (once per 184 days) and 4.8.1.1 .2J (18 months test) The Surveillances 4.8.1 .. 2.L6 and 4.8.1.l2.b.2 verify that the diesel generators are capable of synchonizing with the offiite electrical system and loaded to greater than or equal to continuous rating of the machine. A minimum time of 60 minutes is required to stabilize engine temperatues, while MILLSTONE - UNIT 3 B 314 8-1c Amendment No. 97,44, 43, 494, Q&Q CYV a Af 5-9L- /5

LBDCR No. 04-MP3-015 February 24, 2005 314.8 ELECIRICAL POWER SYSTEMS BASES m miing the time that the diesel generator is connected to the offsite source. Surveillance Requirement 4.8.1.1.2j requires demonstration once per 18 months that the diesel generator can start and run continuously at full load capability for an interval of not less than 24 hours1 days <br />0.143 weeks <br />0.0329 months <br />, 2 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> of which are at a load equivalent to 110% of the continuous duty rating and the remainder of the time at a load equivalent to the continuous duty rating of the diesel generator. The load band is provided to avoid routine overloading ofthe diesel generator. Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain diesel generator OPERABILITY. The load band specified accounts for instrumentation l inaccuracies using plant computer and for the operational control capabilities and human factor characteristics. The note (*) acknowledges that momentauy transient outside the load range shall not invalidate the test. Surveilance Requirements 4.8.1.1.2&S (Monthly). 4.8.1.1.2.bl (Once per 184 Daayfs. 4.8.1.1.2..41b (18 Month Test). 4.8.1(.1.2.g.5 (18 Month Test) and 4.8.1.1 .2.g.6.b (18 Month Test) Several diesel generator surveillance requirements specify that the emergency diesel generators am started from a standby condition. Standby conditions for a diesel generator means the diesel engine coolant and lubricating oil are being cirulated and temperatures are maintained within design ranges. Design ranges for standby temperatures ae greater than or equal to the low temperature alarm setpoints and less than or equal to the standby "keep-wanr" heater shutoff temperatures for each respective sub-system. Surveillance Requirement 4.8.1.1.2A (18 Month Test The existing "standby condition" stipulation contained in specification 4.8.1.12.a. is superseded when performing the hot restart demonstration required by 4.8.1.1.2j. M[LSTONE - UNIT 3 B 314 8-Id Amendment No. R, 44, 4 , 494,

                                                         /3gko          URIC-          CJ     -      SMl

ELECTRICAL POWER SYSTEMS BASES A.C. SOURCES. D.C. SOURCES, and ONSITE POWER DISTRIBUTION (Continued) The Surveillance Requirement for demonstrating the OPERABILITY of the station batteries are based on the recommendations of Regulatory Guide 1.129,

'Maintenance Testing and Replacement of Large Lead Storage Batteries for Nuclear Power Plants," February 1978, and IEEE Std 450-1975 & 1980, "IEEE Recommended Practice for Maintenance, Testing, and Replacement of Large Lead Storage Batteries for Generating Stations and Substations." Sections 5 and 6 of IEEE Std 450-1980 replaced Sections 4 and 5 of IEEE Std 450-1975, otherwise the balance of IEEE Std 450-1975 applies.

Verifying average electrolyte temperature above the minimum for which the battery was sized, total battery terminal voltage on float charge, connection resistance values, and the performance of battery service and discharge tests ensures the effectiveness of the charging system, the ability to handle high discharge rates, and compares the battery capacity at that time with the rated capacity. Table 4.8-2a specifies the normal limits for each designated pilot cell and each connected cell for electrolyte level, float voltage, and specific gravity. The limits for the designated pilot cells float voltage and specific gravity, greater than 2.13 volts and 0.015 below the manufacturer's full charge specific gravity or a battery charger current that had stabilized at a low value, is characteristic of a charged cell with adequate capacity. The normal limits for each connected cell for float voltage and specific gravity, greater than 2.13 volts and not more than 0.020 below the manufacturer's full charge specific gravity with an average specific gravity of all the connected cells not more than 0.010 below the manufacturer's full charge specific gravity, ensures the OPERABILITY and capability of the battery. Operation with a battery cell's parameter outside the normal limit but within the allowable value specified in Table 4.8-2a is permitted for up to 7 days. During this 7-day period: (1) the allowable values for electrolyte level ensures no physical damage to the plates with an adequate electron transfer capability; (2) the allowable value for the average specific gravity of all the cells, not more than 0.020 below the manufacturer's recommended full charge specific gravity, ensures that the decrease in rating will be less than the safety margin provided in sizing; (3) the allowable value for an individual cell's specific gravity, ensures that an individual cell's specific gravity will not be more than 0.040 below the manufacturer's full charge specific gravity and that the overall capability of the battery will be maintained within an acceptable limit; and (4) the allowable value for an individual cell's float voltage, greater than 2.07 volts, ensures the battery's capability to perform its design function. MILLSTONE - UNIT 3 B 3/4 8-2 Amendment No. 0P310 C~ap (Xn Do/i earl how ff$qcj+^Yr l^nfni Anrig 1 I 0QQ

ELECTRICAL POWER SYSTEMS BASES 3/4.8.4 DELETED MILLSTONE - U0IT 3 8 3/4 8-3 IAnendment No. ?F, #i, Xpl, 177, 192 0681

LBDCR 04-MP3-002 314.9 RMO&O OPHEM M March25, 2004 BASES V4.9.1 PORON MCJE AfIQN The limitations on reactivit condions during RBFLING ensur that: (1) the reactor will remain Subcritical during CORE ALTEAIONS, and (2)a uniform boron concentration Is maintained for reactivty control Inthe water volume having direct access to the reactor vessel. The value of 095 or less for Keincludes a 1% kk conservative allowance for umctantfies. Similarly, the boron concentration vlue specified in the CORE OPERATING LMITS REPORT includes a conservatve uetainty aowance of S0 ppm boon. he boron concentrationsspecified I ffic CORE OPERATING LIMITS REPORT, provides for boron measurement uncertainty between iespent fhed pool and the RWST. The locking closed of the required valves durig refaelink opraions precludes the pos lity of uncontroled boron dilution of the dipoon of he . his action prevents flow to the RCS of unborated water by closing flow p fm sources of unborated water. MODE ZERO shall be the Operational MODE where all fuel assemblies bave been removed from co iment to thebSpnt Fuel PooL Te ical Speification Table L2 defimes MODE 6 as apuel in the aorves withihe vsse head closure bolts less than fly tensioned orwitlthe head removed." Withno ful the vssel thedefi on forMODE6no longerapplies.The tmsition from -MODE 6 to MODE ZERO occurs when the last fuel assembly of a full core offload has been transfetred to the Spent Fuel Pool and has cleared the transfer canal while Intransit to a storage location. This will:

• Ensure Technical Specificafions regarding sampling the transfer canal boron concentration ar observed (49.1.1.2);
• Ensure that MODE 6 Technical Specification requirements are Wnt relaxed prematurely during hel movement In containment.

314.9.1.2. BORON CONCENIVATION IN-Sew anS POOL D ng nomal Spent Fuel Pool operaton, the spent fuel racs are capable of maintang Keff at less than or equl to 0.95 Inan unborated water enonmet This Is accpmplished in Region 1,2, and 3 storage racks by the combinaion of geomtry of th rack spacing, the use of fixed neutron absorbers in some fud storage regins, the limits on fuel bumup, fuel enrichment and mimum fuel decay tirm and the use of bocg devices incertain fuel storage locations. Te boron rcqui emntin theuentfuelpool spefied 1in3.9.1. 2 e stinthe event of a fuel aemblyhanfflig accidentinvolvimg eithera sie doppedor misplacedr l assembly,athe Ke of the spent fuel storage raca will remain less thin or equa to 0.95. 3/4.9.2 rNST rnO The OPERABIL1IY of the Source Range Neutron Flux Monitors ensures that redundant monItoring capability is available to detect changes inthe reactivity condition of the core. 314093 DECAYTIME The minmum requement forreactor.subcriticality priorto movement of irradiated fuel assemblies Inthe reactor vessel ensures that sufficient time Uas elapsed to allow the radioactive decay of the short-lived fission products. is decay time Is consistent with the assumptions used in the safety analyses. tVMLWONE-UN1T3 B 314 9-1 Amendment No. 4-2,60, 46, 4*9,

                *                                             ,        O(lCao > t                   S-    g5

3/4.9 REFUELING OPERATIONS BASES 3/4.9.4 CONTAINMENT BUILDING PENETRATIONS The requirements on containment penetration closure and OPERABILITY ensure that a release of radioactive material within containment to the environment will be minimized. The OPERABILITY, closure restrictions, and administrative controls are sufficient to minimize the release of radioactive material from a fuel element rupture based upon the lack of containment pressurization potential during the movement of fuel within containment. The containment purge valves are containment penetrations and must satisfy all requirements specified for a containment penetration. This specification is applicable during the movement of new and spent fuel assemblies within the containment building. The fuel handling accident analyses assume that during a fuel handling accident some of the fuel that is dropped and some of the fuel impacted upon is damaged. Therefore, the movement of either new or irradiated fuel can cause a fuel handling accident, and this specification is applicable whenever new or irradiated fuel is moved within the containment. Containment penetrations, including the personnel access hatch doors and equipment access hatch, can be open during the movement of fuel provided that sufficient administrative controls are in place such that any of these containment penetrations can be closed within 30 minutes. Following a Fuel Handling Accident, each penetration, including the equipment access hatch, is closed such that a containment atmosphere boundary can be established. However, if it is determined that closure of all containment penetrations would represent a significant radiological hazard to the personnel involved, the decision may be made to forgo the closure of the affected penetration(s). The containment atmosphere boundary is established when any penetration which provides direct access to the outside atmosphere is closed such that at least one barrier between the containment atmosphere and the outside atmosphere is established. Additional actions beyond establishing the containment atmosphere boundary, such as installing flange bolts for the equipment access hatch or a containment penetration, are not necessary. Administrative controls for opening a containment penetration require that one or more designated persons, as needed, be available for isolation of containment from the outside atmosphere. Procedural controls are also in place to ensure cables or hoses which pass through a containment opening can be quickly removed. The location of each cable and hose isolation device for those cables and hoses which pass through a containment opening is recorded to ensure timely closure of the containment boundary. Additionally, a closure plan is developed for each containment opening which includes an estimated time to close the containment opening. A log of personnel designated for containment closure is maintained, including identification of which containment openings each person has responsibility for closing. As necessary, equipment will be pre-staged to support timely closure of a containment penetration. MILLSTONE - UNIT 3 B 3/4 9-1la Amendment No. X2,60, i, 203, 219

3/4.9 REFUELING OPERATIONS BASES 3/4.9.4 CONTAINMENT BUTLDING PENETRATIONS (Continued) The ability to close the equipment access hatch penetration within 30 minutes is verified each refueling outage prior to the first fuel movement in containment with the equipment access hatch open. Prior to opening a containment penetration, a review of containment penetrations currently open is performed to verify that sufficient personnel are designated such that all containment penetrations can be closed within 30 minutes. Designated personnel may have other duties, however, they must be available such that their assigned containment openings can be closed within 30 minutes. Additionally, each new work activity inside containment is reviewed to consider its effect on the closure of the equipment access hatch, at least one personnel access hatch door, and/or other open containment penetrations. The required number of designated personnel are continuously available to perform closure of their assigned containment openings whenever fuel is being moved within the containment. Controls for monitoring radioactivity within containment and in effluent paths from containment are maintained consistent with General Design Criterion 64. Local area radiation monitors, effluent discharge radiation monitors, and containment gaseous and particulate radiation monitors provide a defense-in-depth monitoring of the containment atmosphere and effluent releases to the environment. These monitors are adequate to identify the need for establishing the containment atmosphere boundary. When containment penetrations are open during a refueling outage under administrative control for extended periods of time, routine grab samples of the containment atmosphere, equipment access hatch, and personnel access hatch will be required. The containment atmosphere is monitored during normal and transient operations of the reactor plant by the containment structure particulate and gas monitor located in the upper level of the Auxiliary Building or by grab sampling. Normal effluent discharge paths are monitored during plant operation by the ventilation particulate samples and gas monitors in the Auxiliary Building. Administrative controls are also in place to ensure that the containment atmosphere boundary is established if adverse weather conditions which could present a potential missile hazard threaten the plant. Weather conditions are monitored during fuel movement whenever a containment penetration, including the equipment access hatch and personnel access hatch, is open and a storm center is within the plant monitoring radius of 150 miles. The administrative controls ensure that the containment atmosphere boundary can be quickly established (i.e. within 30 minutes) upon determination that adverse weather conditions exist which pose a significant threat to the Millstone Site. A significant threat exists when a hurricane warning or tornado warning is issued which applies to the Millstone Site, or if an average wind speed of 60 miles an hour or greater is recorded by plant meteorological equipment at the meteorological tower. If the meteorological equipment is inoperable, information from the National Weather Service can be used as a backup in determining plant wind speeds. Closure of containment penetrations, including the equipment access hatch penetration and at least one personnel access hatch door, begin immediately upon determination that a significant threat exists. MILL~STONE - UNITs 3 B 314 9-2 Amendment No, 4I-9, 219

3/4.9 REFUELING OPERATIONS BASES 3/4.9.5 COMMUNICATIONS The requirement for communications capability ensures that refueling station personnel can be promptly informed of significant changes in the facility status or core reactivity conditions during CORE ALTERATIONS. 3/4.9.6 REFUELING MACHINE The OPERABILITY requirements for the refueling machine ensure that: (1) refueling machines will be used for movement of drive rods and fuel assemblies, (2) each crane has sufficient load capacity to lift a drive rod or fuel assembly, and (3) the core internals and reactor vessel are protected from excessive lifting force in the event they are inadvertently engaged during lifting operations. 3/4.9.7 CRANE TRAVEL - SPENT FUEL STORAGE AREAS The restriction on movement of loads over fuel assemblies in the storage pool ensures that in the event this load is dropped: (1) the activity release will be less than the activity release assumed in the design basis fuel handling accident, and (2) the resulting geometry will not result in a critical array. 3/4.9.8 RESIDUAL HEAT REMOVAL AND COOLANT CIRCULATION 3/4.9.8.1 HIGH WATER LEVEL BACKGROUND The purpose of the Residual Heat Removal (RHR) System in MODE 6 is to remove decay heat and sensible heat from the Reactor Coolant System (RCS), as required by GDC 34, to provide mixing of borated coolant and to prevent boron stratification. Heat is removed from the RCS by circulating reactor coolant through the RHR heat exchanger(s), where the heat is transferred to the Reactor Plant Component Cooling Water System. The coolant is then returned to the RCS via the RCS cold leg(s). Operation of the RHR system for normal cooldown or decay heat removal is manually accomplished from the control room. The heat removal is manually accomplished from the control room. The heat removal rate is adjusted by controlling the flow of reactor coolant through the RHR heat exchanger(s) and the bypass. Mixing of the reactor coolant is maintained by this continuous circulation of reactor coolant through the RHR system. MILLSTONE - UNIT 3 B 3/4 9-2a Amendment No.21[9i

3/4.9 REFUELING OPERATIONS BASES 3/4.9.8.1 HIGH WATER LEVEL (continued) APPLICABLE SAFETY ANALYSES If the reactor coolant temperature is not maintained below 200'F, boiling of the reactor coolant could result. This could lead to a loss of coolant in the reactor vessel. Additionally, boiling of the reactor coolant could lead to a reduction in boron concentration in the coolant due to boron plating out on components near the areas of the boiling activity. The loss of reactor coolant and the reduction of boron concentration in the reactor coolant would eventually challenge the integrity of the fuel cladding, which is fission product barrier. One train of the RHR system is required to be operational in MODE 6, with the water level 2 23 ft above the top of the reactor vessel flange to prevent this challenge. The LCO does permit deenergizing the RHR pump for short durations, under the conditions that the boron concentration is not diluted. This conditional deenergizing of the RHR pump does not result in a challenge to the fission product barrier. APPLICABILITY One RHR loop must be OPERABLE and in operation in MODE 6, with the water level 2 23 ft above the top of the reactor vessel flange, to provide decay heat removal. The 23 ft level was selected because it corresponds to the 23 ft requirement established for fuel movement in LCO 3.9.10, "Water Level - Reactor Vessel." Requirements for the RHR system in other MODES are covered by LCOs in Section 3.4, Reactor Coolant System (RCS), and Section 3.5, Emergency Core Cooling Systems (ECCS). RHR loop requirements in MODE 6 with the water level < 23 ft are located in LCO 3.9.8.2, "Residual Heat Removal (RHR) and Coolant Circulation-Low Water Level." LIMITING CONDITION FOR OPERATION The requirement that at least one RHR loop be in operation ensures that: (1) sufficient cooling capacity is available to remove decay heat an maintain the water in the reactor vessel below 1400 F as required during the REFUELING MODE, and (2) sufficient coolant circulation is maintained through the core to minimize the effect of a boron dilution incident and prevent stratification. An OPERABLE RHR loop includes an RHR pump, a heat exchanger, valves, piping, instruments and controls to ensure an OPERABLE flow path. An operating RHR flow path should be capable of determining the low-end temperature. The flow path starts in one of the RCS hot legs and is returned to the RCS cold legs. The LCO is modified by a note that allows the required operating RHR loop to be removed from service for up to 1 hour per 8-hour period. This permits operations such as core mapping or alterations in the vicinity of the reactor vessel hot leg nozzle and RCS to RHR isolation valve testing. During this I-hour period, decay heat is removed by natural connection to the large mass of water in the refueling cavity. MILLSTONE - UNIT 3 B 3/4 9-3 AmendmentNo.4 107 219

3/4.9 REFUELING OPERATIONS BASES 3/4.9.8.1 HIGH WATER LEVEL (continued) ACTIONS RHR loop requirements are met by having one RHR loop OPERABLE and in operations, except as permitted in the Note to the LCO. If RHR loop requirements are not met, there will be no forced circulation to provide mixing to establish uniform boron concentrations. Reduced boron concentrations cannot occur by the addition of water with a lower boron concentration than that contained in the RCS because all of unborated water sources are isolated. Reduced boron concentrations can occur by the addition of water with lower boron concentration that contained in the RCS. Therefore, actions that result in an unplanned boron dilution shall be suspended immediately. If RHR loop requirements are not met, actions shall be taken immediately to suspend loading of irradiated fuel assemblies in the core. With no forced circulation cooling, decay heat removal from the core occurs by natural convection to the heat sink provided by the water above the core. A minimum refueling water level of 23 ft above the reactor vessel flange provides an adequate available heat sink. Suspending any operation that would increase decay heat load, such as loading a fuel assembly, is a prudent action under this condition. If RHR loop requirements are not met, actions shall be initiated and continued in order to satisfy RHR loop requirements. With the unit in MODE 6 and the refueling water level 2 23 ft above the top of the reactor vessel flange, corrective actions shall be initiated immediately. If RHR loop requirements are not met, all containment penetrations providing direct access from the containment atmosphere to the outside atmosphere must be closed within 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />. With the RHR loop requirements not met, the potential exists for the coolant to boil and release radioactive gas to the containment atmosphere. Closing containment penetrations that are open to the outside atmosphere ensures dose limits are not exceeded. The Completion Time of 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> is reasonable, based on the low probability of the coolant boiling in that time. Surveillance Requirement This Surveillance demonstrates that the RHR loop is in operation and circulating reactor coolant. The flow rate is determined by the flow rate necessary to provide sufficient decay heat removal capability and to prevent thermal and boron stratification in the core. The frequency of 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> is sufficient, considering the flow, temperature, pump control, and alarm indications available to the operator in the control room for monitoring the RHR system. MILLSTONE - UNIT 3 B 3/4 94 Amendment No. 107, 219

BASES 3/4.9.8.2 LOW WATER LEVEL BACKGROUND The purpose of the RHR System In MODE 6 is to remove decay heat and sensible heat from the Reactor Coolant System (RCS), as required by GDC 34, to provide mixing of borated coolant, and to prevent boron stratification. Heat is removed from the RCS by circulating reactor coolant through the RHR heat exchangers where the heat is transferred to the Component Cooling Water System. The coolant is then returned to the RCS via the RCS cold leg(s). Operation of the RHR System for normal cooldown decay heat removal is manually accomplished from the control room. The heat removal rate is adjusted by controlling the flow of reactor coolant through the RHR heat exchanger(s) and the bypass lines. Mixing of the reactor coolant is maintained by this continuous circulation of reactor coolant through the RHR system. APPLICABLE SAFETY ANALYSES If the reactor coolant temperature is not maintained below 2000F, boiling of the reactor coolant could result. This could lead to a loss of coolant in the reactor vessel. Additionally, boiling of the reactor coolant could lead to a reduction in boron concentration in the coolant due to the boron plating out on components near the areas of the boiling activity. The loss of reactor coolant and the reduction of boron concentration in the reactor coolant will eventually challenge the integrity of the fuel cladding, which is a fission product barrier. Two trains of the RHR System are required to be OPERABLE, and one train in operation, in order to prevent this challenge. LIMITING CONDITION FOR OPERATION In MODE 6, with the water level < 23 ft above the top of the reactor vessel flange, both RHR loops must be OPERABLE. Additionally, one loop of RHR must be in operation in order to provide:

a. Removal of decay heat;

b. Mixing of borated coolant to minimize the possibility of criticality; and

c. Indication of reactor cooling temperature.

The requirement to have two RHR loops OPERABLE when there is less than 23 feet of water above the reactor vessel flange ensures that a single failure of the operating RHR loop will not result in a complete loss of residual heat removal capability. With the reactor vessel head removed and at least 23 feet of water above the reactor pressure vessel flange, a large heat sink is available for core cooling. Thus, in the event of a failure of the operating RHR loop, adequate time is provided to initiate emergency procedure to cool the core. MILLSTONE - UNIT 3 B 3/4 9-5 Amendment No.107 0287 APR 2 1995

LBDCR No. 04-MP3-015 February 24, 2005 BASES 3i4.9.8.2 LOW WATER LEVEL (continued An OPERABLE RHR loop consists of an ERR pump, a beat exchanger, valves, piping, instruments, and controls to ensure an OPERABLE flow path. An operating RHR flow path should be capable ofdetermining the low end temperature. The flow path starts in one of the RCS hot legs and is returned to the RCS cold legs. APPLCALI Two RHR loops are required to be OPERABLE, and one RHR loop must be in operation in MODE 6, with the water level < 23 ft above the top of the reactor vessel flange, to provide decay heat removal. Requirements for the RHR System In other MODES are covered by LCOs in Section 3.5, Emergency Core Cooling Systems (ECCS). RHR loop requirements in MODE 6 with the water level 2 23 fR are located in LCO 3.9.8.1, "Residual Removal (RH) AND Coolant Circulation-High Water Level." AMIIONS

a. Ifless than the required number ofRR loops are OPERABLE, actions shall be immediately initiated and continued until the ERR loop is restored to OPERABLE status and to operation, or until 2 23 ft of water level is established above the reactor vessel flange. When the water level is 2 23 fi above the reactor vessel flange, the Applicability dhanges to that of LCO 3.9.8.1, and only one RHR loop is required to be OPERABLE and in operation. An immediate Completion Time is necessary for an operator to initiate corrective action.

b. If no RHR loop is in operation, there will be no forced circulation to provide mixing to establish uniform boron concentrations. Reduced boron concentrations cannot occur by the addition of water with a low boron concentration than that contained in the RCS, because all of the unborated water sources are Isolated.

If no RHR loop is in operation, actions shall be initiated immediately, and continued, to restore one RHR loop to operation. Since the unit is in AC17ONS 'a' and 'b' concurrently, the restoration of two OPERABLE RHR loops and one operating ER Rloop should be accomplished expeditiously. If no RR loop is in operation, all containment penetrations providing direct access from the containment atmosphere to the outside atmosphere must be closed within 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />. With the RHR loop requirements not met, the potential exists for the coolant to boil and release radioactive gas to the containment atmosphere. Closing containment penetrations that are open to the outside atmosphere ensures that dose limits are not exceeded. The Completion Time of4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> is reasonable, based on the lowprobability of the coolant boiling in that time. MILLSTONE - UNIT 3 B 314 96 Amendment No. 40, mou5

3/4.9 REFUELING OPERATIONS BASES Surveillance Requirement This Surveillance demonstrates that one RHR loop is in operation and circulating reactor coolant. The flow rate is determined by the flow rate necessary to provide sufficient decay heat removal capability and to prevent thermal and boron stratification in the core. In addition, during operation of the RHR loop with the water level in the vicinity of the reactor vessel nozzles, the RHR pump suction requirements must be met. The Frequency of 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> is sufficient, considering the flow, temperature, pump control, and alarm indications available to the operator for monitoring the RHR System in the control room. MILLSTONE - NT 3 B 3/4 9-7 Amendment No. 4lO, 219

3/4.9 REFUELING OPERATIONS BASES 3/4.9.10 AND 3/4.9.11 WATER LEVEL - REACTOR VESSEL AND STORAGE POOL The restrictions on minimum water level ensure that sufficient water depth is available to remove 99% of the assumed 10% iodine gap activity released from the rupture of an irradiated fuel assembly. The minimum water depth is consistent with the assumptions of the safety analysis. I MILLSTONE - UNIT 3 B 3/4 9-8 Amendment No. 39, 410,410, 4-9, 484, 89, 203, 219

BASES 3/4.9.13 SPENT FUEL POOL - REACTIVITY (continued) use of fixed neutron absorbers in the racks, a maximum nominal 5 weight percent fuel enrichment, and the use of blocking devices in certain fuel storage locations, as specified by the interface requirements shown in Figure 3.9-2. Maintaining Keff at less than or equal to 0.95 is accomplished in Region 1 4-OUT-OF-4 storage racks by the combination of geometry of the rack spacing, the use of fixed neutron absorbers in the racks, and the limits on fuel enrichment/fuel burnup specified in Figure 3.9-1. Maintaining K¢,f at less than or equal to 0.95 is accomplished in Region 2 storage racks by the combination of geometry of the rack spacing, the use of fixed neutron absorbers in the racks, and the limits on fuel enrichment/fuel burnup specified in Figure 3.9-3. Maintaining Kefs at less than or equal to 0.95 is accomplished in Region 3 storage racks by the combination of geometry of the rack spacing, and the limits on fuel enrichment/fuel burnup and fuel decay time specified in Figure 3.9-4. Fixed neutron absorbers are not credited in the Region 3 fuel storage racks. The limitations described by Figures 3.9-1, 3.9-2, 3.9-3 and 3.9-4 ensure that the reactivity of the fuel assemblies stored in the spent fuel pool are conservatively within the assumptions of the safety analysis. Administrative controls have been developed and instituted to verify that the fuel enrichment, fuel burnup, fuel decay times, and fuel interface restrictions specified in Figures 3.9-1, 3.9-2, 3.9-3 and 3.9-4 are complied with. 3/4.9.14 SPENT FUEL POOL - STORAGE PATTERN The limitations of this specification ensure that the reactivity conditions of the Region 1 3-OUT-OF-4 storage racks and spent fuel pool keff will remain less than or equal to 0.95. The Cell Blocking Devices in the 4th location of the Region I 3-OUT-OF-4 storage racks are designed to prevent inadvertent placement and/or storage of fuel assemblies in the blocked locations. The blocked location remains empty to provide the flux trap to maintain reactivity control for fuel assemblies in adjacent and diagonal locations of the STORAGE PATTERN. STORAGE PATTERN for the Region I storage racks will be established and expanded from the walls of the spent fuel pool per Figure 3.9-2 to ensure definition and control of the Region I 3-OUT-OF-4 Boundary to other Storage Regions and minimize the number of boundaries where a fuel misplacement incident can occur. MILLSTONE - UNIT 3 B 3/4 9-9 Amendment No. }i, JOY, Jp7, 0F, 0898 MI 01, "Revised April 2 2002"

REFUELING OPERATIONS BASES 3/4.9.13 SPENT FUEL POOL - REACTIVITY (continued) Maintaining K*ff at less than or equal to 0.95 is accomplished in Region 3 storage racks by the combination of geometry of the rack spacing, and the limits on fuel enrichment/fuel burnup and fuel decay time specified in Figure 3.9-4. Fixed neutron absorbers are not credited in the Region 3 fuel storage racks. The limitations described by Figures 3.9-1, 3.9-2, 3.9-3 and 3.9-4 ensure that the reactivity of the fuel assemblies stored in the spent fuel pool are conservatively within the assumptions of the safety analysis. Administrative controls have been developed and instituted to verify that the fuel enrichment, fuel burnup, fuel decay times, and fuel interface restrictions specified in Figures 3.9-1, 3.9-2, 3.9-3 and 3.9-4 are complied with. 3/4.9.14 SPENT FUEL POOL - STORAGE PATTERN The limitations of this specification ensure that the reactivity conditions of the Region 1 3-OUT-OF-4 storage racks and spent fuel pool keff will remain less than or equal to 0.95. The Cell Blocking Devices in the 4th location of the Region 1 3-OUT-OF-4 storage racks are designed to prevent inadvertent placement and/or storage of fuel assemblies in the blocked locations. The blocked location remains empty to provide the flux trap to maintain reactivity control for fuel assemblies in adjacent and diagonal locations of the STORAGE PATTERN. STORAGE PATTERN for the Region 1 storage racks will be established and expanded from the walls of the spent fuel pool per Figure 3.9-2 to ensure definition and control of the Region 1 3-OUT-OF-4 Boundary to other Storage Regions and minimize the number of boundaries where a fuel misplacement incident can occur. MILLSTONE - UNIT 3 B 3/4 9-9 Amendment No. IF, 10P, 7j7, M,203 0841 IFY 9

3/4.10 SPECIAL TEST EXCEPTIONS BASES 3/4.10.1 SHUTDOWN MARGIN This special test exception provides that a minimum amount of control rod worth is immediately available for reactivity control when tests are performed for control rod worth measurement. This special test exception is required to permit the periodic verification of the actual versus predicted core reactivity condition occurring as a result of fuel burnup or fuel cycling operations. 3/4.10.2 GROUP HEIGHT, INSERTION, AND POWER DISTRIBUTION LIMITS This special test exception permits individual control rods to be positioned outside of their normal group heights and insertion limits during the performance of such PHYSICS TESTS as those required to: (1) measure control rod worth, and (2) determine the reactor stability index and damping factor under xenon oscillation conditions. 3/4.10.3 PHYSICS TESTS This special test exception permits PHYSICS TESTS to be performed at less than or equal to 5% of RATED THERMAL POWER with the RCS Tav slightly lower than normally allowed so that the fundamental nuclear characteristics of the core and related instrumentation can be verified. In order for various charac-teristics to be accurately measured, it is at times necessary to operate outside the normal restrictions of these Technical Specifications. For instance, to measure the moderator temperature coefficient at BOL, it is necessary to position the various control rods at heights which may not normally be allowed by Specification 3.1.3.6 which in turn may cause the RCS Tvg to fall slightly below the minimum temperature of Specification 3.1.1.4. 3/4.10.4 REACTOR COOLANT LOOPS This special test exception permits reactor criticality under no flow conditions and is required to perform certain STARTUP and PHYSICS TESTS while at low THERMAL POWER levels. 3/4.10.5 DELETED KILLSTONE - UNIT 3 B 3/4 10-1 Amendment No. fl7, 0808 207 - JUL .30 2002

THIS PAGE INTENTIONALLY LEFT BLANK MILLSTONE - UNIT 3 B 3/4 10-2 Amendment No. 717, 0808 207 - JUL 3 0 Wj3

3/4.11 DELETED BASES 3/4.11.1- DELETED 3/4.11.2 - DELETED 3/4/11/3 - DELETED MILLSTONE - UNIT 3 B 3/4 11-1 Amendment No.188 oe9s il

This page intentionally left blank KILLSTONE - UNIT 3 B 3/4 11 Amendment No.188 0695

This page intentionally left blank KILLSTONE - UNIT 3 B 3/4 11-3 Amendment No. fy,188 ONGS

SECTION 5.0 DESIGN FEATURES

5.0 DESIGN FEATURES 5.1 SITE LOCATION The Unit 3 Containment Building is located on the site at Millstone Point in Waterford, Connecticut. The nearest site boundary on land is 1719 feet northeast of the containment building wall (1627 feet northeast of the elevated stack), which is the minimum distance to the boundary of the exclusion area as described in 10 CFR 100.3. No part of the site that is closer than these distances shall be sold or leased except to Dominion Nuclear Connecticut, Inc. or its corporate affiliates for use in conjunction with normal utility operations. 5.2 DELETED MILLSTONE - UNIT 3 5-1 Amendment No. 212 0944 SEP 17 2M2

THIS PAGE INTENTIONALLY LEFT BLANK 5-2 Amendment No. 212 MILLSTONE - UNIT 3 0824 SEP 1? W

THIS PAGE INTENTIONALLY LEFT BLANK MILLSTONE - UNIT 3 5-3 Amendment No. 212 0824 SEP 17 2ax

THIS PAGE INTENTIONALLY LEFT BLANK MILLSTONE - UNIT 3 5-4 Amendment No- 2 12 0824 SEP 17 2002

DESIGN FEATURES 5.3 REACTOR CORE FUEL ASSEMBLIES 5.3.1 The core shall contain 193 fuel assemblies. Each fuel assembly shall consist of 264 zircaloy-4 or ZIRLO clad fuel rods with an initial composition of natural uranium dioxide or a maximum nominal enrichment of 5.0 weight percent U-235 as fuel material. Limited substitutions of zircaloy-4, ZIRLO or stainless steel filler rods for fuel rods, in accordance with NRC-approved applications of fuel rod configurations, may be used. Fuel assembly configurations shall be limited to those fuel designs that have been analyzed with applicable NRC staff-approved codes and methods, and shown by test or cycle-specific reload analyses to comply with all fuel safety design bases. Each fuel rod shall have a nominal active fuel length of 144 inches. A limited number of lead test assemblies that have not completed representative testing may be placed in nonlimiting core regions. CONTROL ROD ASSEMBLIES 5.3.2 The core shall contain 61 full-length control rod assemblies. The full-length control rod assemblies shall contain a nominal 142 inches of absorber material. The nominal values of absorber material shall be 95.3% hafnium and 4.5% natural zirconium or 80% silver, 15% indium, and 5% cadmium. All control rods shall be clad with stainless steel. 5.4 DELETED 5.5 DELETED MILLSTONE - UNIT 3 5-5 Amendment No. J7, 77, Add 212 0924 SEP 17 am

DESIGN FEATURES 5.6 FUEL STORAGE CRITICALITY 5.6.1.1 The spent fuel storage racks are made up of 3 Regions which are designed and shall be maintained to ensure a K*" less than or equal to 0.95 when flooded with unborated water. The storage rack Regions are:

a. Region 1, a nominal 10.0 inch (North/South) and a nominal 10.455 inch (East/West) center to center distance, credits a fixed neutron absorber (BORAL) within the rack, and can store fuel in 2 storage configurations:

(1) With credit for fuel burnup as shown in Figure 3.9-1, fuel may be.stored in a '4-OUT-OF-4" storage configuration. (2) With credit for every 4th location blocked and empty of fuel, fuel up to 5 weight percent nominal enrichment, regardless of fuel burnup, may be stored in a "3-OUT-OF-4" storage configuration. Fuel storage in this configuration is subject to the interface restrictions specified in Figure 3.9-2.

b. Region 2, a nominal 9.017 inch center to center distance, credits a fixed neutron absorber (BORAL) within the rack, and with credit for fuel burnup as shown in Figure 3.9-3, fuel may be stored in all available Region 2 storage locations.

c. Region 3, a nominal 10.35 inch center to center distance, with credit for fuel burnup and fuel decay time as shown in Figure 3.9-4, fuel may be stored in all available Region 3 storage locations.

The Boraflex contained inside these storage racks is not credited. DRAINAGE 5.6.2 The spent fuel storage pool is designed and shall be maintained to prevent inadvertent draining of the pool below elevation 45 feet. MILLSTONE - UNIT 3 5-6 Amendment No. 39, n,189 0825

DESIGN FEATURES CAPACITY 5.6.3 The spent fuel storage pool contains 350 Region 1 storage locations, 673 Region 2 storage locations and 756 Region 3 storage locations, for a total of 1779 total available fuel storage locations. An additional Region 2 rack with 81 storage locations may be placed in the spent fuel pool, if needed. With this additional rack installed, the Region 2 storage capacity is 754 storage locations, for a total of 1860 total available fuel storage locations. 5.7 DELETED I MILLSTONE - UNIT 3 5-6a Amendment No. Ad, Ad. APEX 212 0825 SEP 17 2Si2

THIS PAGE INTENTIONALLY LEFT BLANK MILLSTONE - UNIT 3 5-7 Amendment NO. 212 0826 SEP 1 7 2W2

SECTION 6.0 ADMINISTRATIVE CONTROLS

ADMINISTRATIVE CONTROLS 6.1 RESPONSIBILITY 6.1.1 The designated officer shall be responsible for overall operation of the Millstone Station Site and shall delegate in writing the succession to this responsibility. The designated manager shall be responsible for overall Unit safe operation and shall delegate in writing the succession to this responsibility. 6.1.2 The Shift Manager shall be responsible for the control room command function. 6.1.3 Unless otherwise defined, the technical specification titles for members of the staff are generic titles. Unit specific titles for the functions and responsibilities associated with these generic titles are identified in appropriate administrative documents. 6.2 ORGANIZATION 6.2.1 OFFSITE AND ONSITE ORGANIZATIONS Onsite and offsite organizations shall be established for unit operation and corporate management, respectively. The onsite and offsite organizations shall include the positions for activities affecting the safety of the nuclear power plant.

a. Lines of authority, responsibility, and communication shall be established and defined for the highest management levels through intermediate levels to and including all operating organization positions. These relationships shall be documented and updated, as appropriate, in the form of organization charts, functional descriptions of departmental responsibilities and relationships, and job descriptions for key personnel positions, or in equivalent forms of documentation.

These requirements shall be documented in the Quality Assurance Program Topical Report.

b. The designated manager shall be responsible for overall unit safe operation and shall have control over those onsite activities necessary for safe operation and maintenance of the plant.

c. The designated officer shall have corporate responsibility for overall plant nuclear safety and shall take any measures needed to ensure acceptable performance of the staff in operating, maintaining, and providing technical support to the plant to ensure nuclear safety.

d. The individuals who train the operating staff and those who carry out radiation protection and quality assurance functions may report to the appropriate onsite manager; however, they shall have sufficient organizational freedom to ensure their independence from operating pressures.

6.2.2 FACILITY STAFF

a. Each on-duty shift shall be composed of at least the minimum shift crew composition shown in Table 6.2-1; MILLSTONE - UNIT 3 6-1 Amendment No. 36, 69, 9G, 435, 14+,

2+2,226

ADMINISTRATIVE CONTROLS FACILITY STAFF (Continued)

b. At least one licensed Operator shall be in the control room when fuel is in the reactor. In addition, while the unit is in MODE 1, 2, 3, or 4, at least one licensed Senior Operator shall be in the control room;

c. At least two licensed Operators shall be present in the control room during reactor startup, scheduled reactor shutdown and during recovery from reactor trips.

d. A radiation protection technician* shall be on site when fuel is I in the reactor;

e. All CORE ALTERATIONS shall be observed and directly supervised by either a licensed Senior Reactor Operator or licensed Senior Reactor Operator Limited to Fuel Handling who has no other concurrent responsibilities during this operation;

f. Deleted

g. Administrative procedures shall be developed and implemented to limit the working hours of unit staff who perform safety-related functions. These procedures should follow the general guidance of the NRC Policy Statement on working hours (Generic Letter No.

82-12).

• The radiation protection technician composition may be less than the minimum I requirements for a period of time not to exceed 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br />, in order to accommodate unexpected absence, provided immediate action is taken to fill the required positions.

MILLSTONE UNIT 3 6-2 Amendment No. If, #i, FF, 212 0827 SEP 1 7 2W,

TABLE 6.2-1 MINIMUM SHIFT CREW COMPOSITION POSITION NUMBER OF INDIVIDUALS REQUIRED TO FILL POSITION MODE 1, 2, 3, or 4 MODE 5 or 6 SM I I I SRO 1 None RO 2 1 PEO 2 1 STA 1* None SM Shift Manager with a Senior Operator license on Unit 3 I SRO Individual with a Senior Operator license on Unit 3 RO Individual with an Operator license on Unit 3 PEO Plant Equipment Operator (Non-licensed) STA Shift Technical Advisor The shift crew composition may be one less than the minimum requirements of Table 6.2-1 for a period of time not to exceed 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> in order to accommodate unexpected absence of on-duty shift crew members provided immediate action is taken to restore the shift crew composition to within the minimum requirements of Table 6.2-1. This provision does not permit any shift crew position to be unmanned upon shift change due to an oncoming shift crewmember being late or absent. During any absence of the Shift Manager from the control room while the I unit is in MODE 1, 2, 3, or 4, an individual with a valid Senior Operator license shall be designated to assume the control room command function. During any absence of the Shift Manager from the control room while the I unit is in MODE 5 or 6, an individual with a valid Senior Operator license or Operator license shall be designated to assume the control room command function.

• The STA position may be filled by an on-shift Senior Reactor Operator only if that Senior Reactor Operator meets the Shift Technical Advisor qualifica-tions of the Commission Policy Statement on Engineering Expertise on Shift.

MILLSTONE - UNIT 3 6-3 Amendment No. fy, 212 0827 SEP 1 7 20W

ADMINISTRATIVE CONTROLS 6.2.3 Deleted. 6.2.4 SHIFT TECHNICAL ADVISOR 6.2.4.1 The Shift Technical Advisor shall provide advisory technical support to the Shift Manager in the areas of thermal hydraulics, reactor engineering, and plant analysis with regard to the safe operation of the unit. I M~ILLSTONE - UNIT 3 6-4 Amendment No. £4, 69, i34,443., 2, , 226

ADMINISTRATIVE CONTROLS 6.3 FACILITY STAFF QUALIFICATIONS 6.3.1 Each member of the facility staff shall meet or exceed the minimum qualifications of ANSI NI8.1-1971

• for comparable positions. Exceptions to this requirement are specified in the Quality Assurance Program.

6.3.2 If the operations manager does not hold a senior reactor operator license for Millstone Unit No. 3, then the operations manager shall have held a senior reactor operator license at a pressurized water reactor, and the assistant operations manager shall hold a senior reactor operator license for Millstone Unit No. 3. I 6.4 TRAINING 6.4.1 A retraining and replacement training program for the facility staff that meets or exceeds the requirements as specified in the Quality Assurance Program and 10 CFR Part 55.59 shall be I maintained. 6.4.2 Deleted. 6.5 Deleted.

• As of November 1, 2001, applicants for reactor operator and senior reactor operator qualification shall meet or exceed the education and experience guidelines of Regulatory Guide 1.8, Revision 3, May 2000.

MILLSTONE - UNIT 3 6-5 Amendment No. 3,X 4, 90, 94, 3, 4-34,, 4-74, 473, 9, e4-2, 226

PAGES 6-6 THROUGH 6-13 HAVE BEEN INTENTIONALLY DELETED. MILLSTONE - UNIT 3 6-6 Amendment No. If, #i, of, Po, SFp, 0634 Aa 7}7, }77, 173

ADMINISTRATIVE CONTROLS 6.6 Deleted. 6.7 Deleted. 6.8 PROCEDURES AND PROGRAMS 6.8.1 Written procedures shall be established, implemented, and maintained covering the activities referenced below:

a. The applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978;

b. The applicable procedures required to implement the requirements of NUREG-0737 and supplements thereto;

c. Refueling operations;

d. Surveillance activities of safety related equipment;

e. Not used.

MILLSTONE - UNIT 3 6-14 Amendment No. fl, Iy,1i1,1y, 0634 11Z. 7H. 171 173

                                                             . 1  1 ,; ,15

AbMINISTRATIVE CONTROLS

f. Not used.

9. Fire Protection Program implementation;

h. Quality controls for effluent monitoring, using the guidance in Regulatory Guide 1.21, Rev. 1, June 1974; and

i. Radiological Effluent Monitoring and Offsite Dose Calculation Manual (REMODCM) implementation except for Section I.E, Radiological Environmental Monitoring.

6.8.2 a. The designated manager or designated officer or designated senior officer may designate specific procedures and programs, or classes of procedures and programs to be reviewed in accordance with the Quality Assurance Program Topical Report.

b. Procedures and programs listed in Specification 6.8.1, and changes thereto, shall be approved by the designated manager or designated officer or by cognizant managers or directors who are designated as the Approval Authority by designated manager or designated officer as specified in administrative procedures. The Approval Authority for each procedure and program or class of procedure and program shall be specified in administrative procedures.

c. Each procedure of Specification 6.8.1, and changes thereto, shall be reviewed and approved in accordance with the Quality Assurance Program Topical Report, prior to implementation. Each procedure of Specification 6.8.1 shall be reviewed periodically as set forth in administrative procedures.

6.8.3 Temporary changes to procedures of Specification 6.8.1 may be made provided:

a. The intent of the original procedure is not altered;

b. The change is approved by two members of the plant management staff, at least one of whom holds a Senior Operator license on the unit affected; and

c. The change is documented, reviewed and approved in accordance with the Quality Assurance Program Topical Report within 14 days of implementation.

MILLSTONE - UNIT 3 6-15 Amendment No. #, fl, Ji, JZ, Ai 0828 }7X, }7X 212 SEP 17 2WR2

ADMINISTRATIVE CONTROLS 6.8.4 The following programs shall be established, implemented, and maintained:

a. Primary Coolant Sources Outside Containment A program to reduce leakage from those portions of systems outside containment that could contain highly radioactive fluids during a serious transient or-accident to as low as practical levels. The systems include the recirculation spray, Safety Injection, charging portion of chemical and volume control, and hydrogen recombiners.

The program shall include the following:

1) Preventive maintenance and periodic visual inspection requirements, and

2) Integrated leak test requirements for each system at refueling cycle intervals or less.

b. In-Plant Radiation Monitoring A program which will ensure the capability to accurately determine the airborne iodine concentration in vital areas under accident conditions. This program shall include the following:

1) Training of personnel,

2) Procedures for monitoring, and

3) Provisions for maintenance of sampling and analysis equipment.

MILLSTONE - UNIT 3 6-15a Amendment No. fy, Fp, 125 1 0423  ;.tj . I 1J4.

ADMINISTRATIVE CONTROLS PROCEDURES AND PROGRAMS (Continued)

c. Secondary Water Chemistry A program for monitoring of secondary water chemistry to inhibit steam generator tube degradation. This program shall include:

1) Identification of a sampling schedule for the critical variables and control points for these variables,

2) Identification of the procedures used to measure the values of the critical variables,

3) Identification of process sampling points, which shall include monitoring the discharge of the condensate pumps for evidence of condenser in-leakage,

4) Procedures for the recording and management of data,

5) Procedures defining corrective actions for all off-control point chemistry conditions, and

6) A procedure identifying: (a) the authority responsible for the interpretation of the data, and (b) the sequence and timing of administrative events required to initiate corrective action.

d. Deleted

e. Accident Monitoring Instrumentation A program which will ensure the capability to monitor plant variables and systems operating status during and following an accident. This program shall include those instruments provided to indicate system operating status and furnish information regarding the release of radioactive materials (Category 2 and 3 instrumentation as defined in Regulatory Guide 1.97, Revision 2) and provide the following:

1) Preventive maintenance and periodic surveillance of instrumentation, MILLSTONE - UNIT 3 6-16 Amendment No. fp,201 0787 4ANO8 W

AfM1NISTAAT1VF CnNTRnis PROCEDURES AND PROGRAMS (Continued)

2) Pre-planned operating procedures and backup instrumentation to be used if one or more monitoring instruments become inoperable, and

3) Administrative procedures for returning inoperable instruments to OPERABLE status as soon as practicable.

f. Containment Leakage Rate Testing Program A program shall be established to implement the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions%. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, 'Performance-Based Containment Leak-Test Program," dated September 1995.

The peak calculated containment internal pressure for the design basis loss of coolant accident, P., is 38.57 psig. The maximum allowable containment leakage rate Las at Pa. shall be 0.3 percent by weight of the containment air per 24 hours1 days <br />0.143 weeks <br />0.0329 months <br />. Leakage rate acceptance criteria are:

1) Containment overall leakage rate acceptance criterion is

                  < 1.0 La. During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are < 0.60 L. for the combined Type B and Type C tests, and < 0.042 La for all penetrations that are Secondary Containment bypass leakage paths, and <0.75 L. for Type A tests;

2) Air lock testing acceptance criteria are:

a. Overall air lock leakage rate is < 0.05 La when tested at > P'.

b. For each door, seal leakage rate is < 0.01 L. when pressurized to > P,.

The provisions of Specification 4.0.2 do not apply to the test frequencies specified in the Containment Leakage Rate Testing Program. The provisions of Specification 4.0.3 are applicable to the Containment Leakage Rate Testing Program.

• An exemption to Appendix J, Option A, paragraph III.D.2(b)(ii), of 10 CFR Part 50, as approved by the NRC on December 6, 1985.

MILLSTONE - UNIT 3 6-17 Amendment No. f , 1R6 0747

ADMINISTRATIVE CONTROLS PROCEDURES AND PROGRAMS (Continued) 6.8.5 Written procedures shall be established, implemented and maintained covering Section I.E, Radiological Environmental Monitoring, of the REMODCM. 6.8.6 All procedures and procedure changes required for the Radiological Environmental Monitoring Program (REMP) of Specification 6.8.5 above shall be reviewed by an individual (other than the author) from the organization responsible for the REMP and approved by appropriate supervision. Temporary changes may be made provided the intent of the original procedure is not altered and the change is documented and reviewed by an individual (other than the author) from the organization responsible for the REMP within 14 days of implementation. 6.9 REPORTING REQUIREMENTS ROUTINE REPORTS 6.9.1 In addition to the applicable reporting requirements of Title 10, Code of Federal Regulations, the following reports shall be submitted to the U.S. Nuclear Regulatory Commission, Document Control Desk, Washington, D.C. 20555, one copy to the Regional Administrator, Region I, and one copy to the NRC Resident Inspector, unless otherwise noted. STARTUP REPORT 6.9.1.1 A summary report of plant startup and power escalation testing shall be submitted following: (1) receipt of an Operating License, (2) amendment to the license involving a planned increase in power level, (3) installation of fuel that has a different design or has been manufactured by a different fuel supplier, and (4) modifications that may have significantly altered the nuclear, thermal, or hydraulic performance of the unit. The Startup Report shall address each of the tests identified in the Final Safety Analysis Report and shall include a description of the measured values of the operating conditions or characteristics obtained during the test program and a comparison of these values with design predictions and specifications. Any corrective actions that were required to obtain satisfactory operation shall also be described. Any additional specific details required in license conditions based on other commitments shall be included in this report. MILLSTONE - UNIT 3 6-17a Amendment No. #i, HP, 2 1 2 0829 SEP 1 200

ADMINISTRATIVE CONTROLS Startup Reports shall be submitted within: (1) 90 days following completion of the Startup Test Program, (2) 90 days following resumption or commencement of commercial power operation, or (3) 9 months following initial criticality, whichever is earliest. If the Startup Report does not cover all three events (i.e., initial criticality, completion of Startup Test Program, and resumption or commencement of commercial operation), supplementary reports shall be submitted at least every 3 months until all three events have been completed. ANNUAL REPORTS* 6.9.1.2 Annual Reports covering the activities of the unit as described below for the previous calendar year shall be submitted in accordance with 10 CFR 50.4. 6.9.1.2a. Deleted I 6.9.1.2b.The results of specific activity analyses in which the reactor coolant exceeded the limits of Specification 3.4.8. The following information shall be included: (1) Reactor power history starting 48 hours2 days <br />0.286 weeks <br />0.0658 months <br /> prior to the first sample in which the limit was exceeded (in graphic and tabular format); (2) Results of the last isotopic analysis for radioiodine performed prior to exceeding the limit, results of analysis while the limit was exceeded and results of one analysis after the radioiodine activity was reduced to less than the limit. Each result should include date and time of sampling and the radioiodine concentrations; (3) Clean-up flow history starting 48 hours2 days <br />0.286 weeks <br />0.0658 months <br /> prior to the first sample in which the limit was exceeded; (4) Graph of the I-131 concentration (jiCi/gm) and one other radioiodine isotope concentration (plCi/gn) as a function of time for the A single submittal may be made for a multiple unit station. The submittal should combine those sections that are common to all units at the station. MILLSTONE - UNIT 3 6-18 Amendment No. 69, 44, 223

ADMINISTRATIVE CONTROLS ANNUAL REPORTS (Continued) duration of the specific activity above the steady-state level; and (5) The time duration when the specific activity of the reactor coolant exceeded the radioiodine limit. The report covering the previous calendar year shall be submitted prior to March 1 of each year. 6.9.1.3 ANNUAL RADIOLOGICAL ENVIRONMENTAL OPERATING REPORT --- NOTE - A single submittal may be made for a multiple unit station. The submittal shall combine sections common to all units at the station. The Annual Radiological Environmental Operating Report covering the operation of the unit during the previous calendar year shall be submitted by May I of each year. The report shall include summaries, interpretations, and analyses of trends of the results of the Radiological Environmental Monitoring Program for the reporting period. The material provided shall be consistent with the objectives outlined in the Radiological Effluent Monitoring and Offsite Dose Calculation Manual (REMODCM), and in 10 CFR Part 50, Appendix I, Sections IV.B.2, IV.B.3, and 1V.C. The Annual Radiological Environmental Operating Report shall include the results of analyses of all radiological environmental samples and of all environmental radiation measurements taken during the period pursuant to the locations specified in the table and figures in the REMODCM, as well as summarized and tabulated results of these analyses and measurements. In the event that some individual results are not available for inclusion with the report, the report shall be submitted noting and explaining the reasons for the missing results. The missing data shall be submitted in the next annual report. 6.9.1.4 RADIOACTIVE EFFLUENT RELEASE REPORT

-------                                         NOTE ---

A single submittal may be made for a multiple unit station. The submittal shall combine sections common to all units at the station; however, for units with separate radwaste systems, the submittal shall specifyr the releases of radioactive material from each unit. The Radioactive Effluent Release Report covering the operation of the unit in the previous year shall be submitted prior to May I of each year in accordance with 10 CFR 50.36a. The report shall include a summary of the quantities of radioactive liquid and gaseous effluents and solid waste released from the unit. The material provided shall be consistent with the objectives outlined in the REMODCM and in conformance with 10 CFR 50.36a and 10 CFR Part 50, Appendix I, Section W.B.I. MILLSTONE - UNIT 3 6-19 Amendment No. 24, -P, 69,86, 48, 223 24-5,

ADMINISTRATIVE CONTROLS 6.9.1.5 Deleted I CORE OPERATING LIMITS REPORT 6.9.1.6 a Core operating limits shall be established and documented in the CORE OPERATING LIMITS REPORT before each reload cycle or any remaining part of a reload cycle for the following:

1. Overtemperature AT and Overpower AT setpoint parameters for Specification 2.2.1,

2. Shutdown Margin for Specifications 3/4.1.1.1.1, 3/4.1.1.1.2, and 3/4.1.1.2,

3. Moderator Temperature Coefficient BOL and EOL limits and 300 ppm surveillance limit for Specification 3/4.1.1.3.

MILLSTONE - UNIT 3 6-19a Amendment No. 24, , 9,69 , 148S, 223 Ml

ADMINISTRATIVE CONTROLS CORE OPERATING LIMITS REPORT (Cont.)

4. Shutdown Rod Insertion Limit for Specification 3/4.1.3.5,

5. Control Rod Insertion Limits for Specification 3/4.1.3.6,

6. Axial Flux Difference Limits, target band, and APLND for Specifications 3/4.2.1.1 and 3/4.2.1.2,

7. Heat Flux Hot Channel Factor, K(z), W(z), APLND, and W(Z)BL for Specifications 3/4.2.2.1 and 3/4.2.2.2.

8. Nuclear Enthalpy Rise Hot Channel Factor, Power Factor Multiplier for Specification 3/4.2.3.

9. DNB Parameters for Specification 3/4.2.5.

10. Shutdown Margin Monitor minimum count rate for Specification 3/4.3.5.

11. Boron Concentration for Specification 3/4.9.1 .1.

6.9.1.6.b The analytical methods used to determine the core operating limits shall be those previously reviewed and approved by the NRC in:

1. WCAP-9272-P-A, "WESTINGHOUSE RELOAD SAFETY EVALUATION METHODOLOGY," (W Proprietary). (Methodology for Specifications 3.1.1.3--Moderator Temperature Coefficient, 3.1.3.5--Shutdown Bank Insertion Limit, 3.1.3.6--Control Bank Insertion Limits, 3.2.1--Axial Flux Difference, 3.2.2--Heat Flux Hot Channel Factor, 3.2.3--Nuclear Enthalpy Rise Hot Channel Factor, 3.1.1.1.1, 3.1.1.1.2, 3.1.1.2 - Shutdown Margin, 3.9.1.1 -- Boron Concentration.)

2. T. M. Anderson to K. Kniel (Chief of Core Performance Branch, NRC), January 31, 1980--

Attachment:

Operation and Safety-Analysis Aspects of an Improved Load Follow Package.

3. NUREG-800, Standard Review Plan, U.S. Nuclear Regulatory Commission, Section 4.3, Nuclear Design, July 1981 Branch Technical Position CPB 4.3-1, Westinghouse Constant Axial Offset Control (CAOC), Revision 2, July 1981.

4. WCAP-10216-P-A-RIA, "RELAXATION OF CONSTANT AXIAL OFFSET CONTROL FQ SURVEILLANCE TECHNICAL SPECIFICATION,"

(E Proprietary). (Methodology for Specifications 3.2.1--Axial Flux Difference [Relaxed Axial Offset Control] and 3.2.2--Heat Flux Hot Channel Factor [W(z) surveillance requirements for FQ Methodology].)

5. WCAP-9561-P-A, ADD. 3, "BARTA-I: A COMPUTER CODE FOR THE BEST ESTIMATE ANALYSIS OF REFLOOD TRANSIENTS--SPECIAL REPORT:

THIMBLE MODELING W ECCS EVALUATION MODEL," (W. Proprietary). (Methodology for Specification 3.2.2--Heat Flux Hot Channel Factor.)

6. WCAP-10266-P-A, Addendum 1, "THE 1981 VERSION OF THE WESTINGHOUSE ECCS EVALUATION MODEL USING THE BASH CODE,"

(W Proprietary). (Methodology for Specification 3.2.2--Heat Flux Hot Channel Factor.) MILLSTONE - UNIT 3 6-20 Amendment No. 24, 47, A0, 69 , 420,,.4, 218

ADMINISTRATIVE CONTROLS CORE OPERATING LIMITS REPORT (Cont.)

7. WCAP-1 1946, "Safety Evaluation Supporting a More Negative EOL Moderator Temperature Coefficient Technical Specification for the Millstone Nuclear Power Station Unit 3," (jW Proprietary).

8. WCAP-10054-P-A, "WESTINGHOUSE SMALL BREAK ECCS EVALUATION MODEL.17 USINGTHENOTRUMP CODE," (W Proprietary).

(Methodology for Specification 3.2.2 - Heat Flux Hot Channel Factor.)

9. WCAP-1 0079-P-A, "NOTRUMP - A NODAL TRANSIENT SMALL BREAK AND GENERAL NETWORK CODE," (W Proprietary). (Methodology for Specification 3.2.2 - Heat Flux Hot Channel Factor.)

10. WCAP-12610, "VANTAGE+ Fuel Assembly Report," ff Proprietary).

(Methodology for Specification 3.2.2 - Heat Flux Hot Channel Factor.)

11. Letter from V. L. Rooney (USNRC) to J. F. Opeka, "Safety Evaluation for Topical Report, NUSCO-1 52, Addendum 4, 'Physics Methodology for PWR Reload Design,' TAC No. M91815," July 18, 1995.

12. Letter from E. J. Mroczka to the USNRC, "Proposed Changes to Technical Specifications, Cycle 4 Reload Submittal - Boron Dilution Analysis," B 13678, December 4, 1990.

13. Letter from D. H. Jaffe (USNRC) to E. J. Mroczka, "Issuance of Amendment (TAC No. 77924)," March 11, 1991.

14. Letter from M. H. Brothers to the USNRC, "Proposed Revision to Technical Specification, Shutdown Margin Requirements and Shutdown Margin Monitor Operability for Modes 3, 4, and 5 (PTSCR 3-16-97), B16447, May 9, 1997.

15. Letter from J. W. Anderson (USNRC) to M. L. Bowling (NNECO), "Issuance of Amendment - Millstone Nuclear Power Station, Unit No. 3 (TAC No. M98699),"

October 21, 1998.

16. WCAP-8301, "LOCTA-IV Program: Loss-of-Coolant Transient Analysis."

17. WCAP-10054-P-A, Addendum 2, "Addendum to the Westinghouse Small Break ECCS Evaluation Model Using the NOTRUMP Code: Safety Injection into the Broken Loop and COST Condensation Model."

18. WCAP-8745-P-A, "Design Bases for the Thermal Overpower AT and Thermal Overtemperature AT Trip Functions," (Westinghouse Proprietary Class 2).

(Methodology for Specification 2.2.1.) MILLSTONE - UNIT 3 6-20a Amendment No. 9+, 40, 218

ADMINISTRATIVE CONTROLS 6.9.1.6.c The core operating limits shall be determined so that all applica-ble limits (e.g. fuel thermal-mechanical limits, core thermal-hydraulic limits, ECCS limits, nuclear limits such as. shutdown margin, and transient and accident analysis limits) of the safety analysis are met. 6.9.1.6.d The CORE OPERATING LIMITS REPORT, including any mid-cycle revisions or supplements thereto, shall be provided upon issuance, for each reload cycle, to the NRC Document Control Desk with copies to the Regional Adminis-trator and Resident Inspector. SPECIAL REPORTS 6.9.2 Special reports shall be submitted to the U.S. Nuclear Regulatory Commission, Document Control Desk, Washington, D.C. 20555, one copy to the Regional Administrator Region I, and one copy to the NRC Resident Inspector, within the time period specified for each report. 6.10 Deleted. 6.11 RADIATION PROTECTION PROGRAM 6.11.1 Procedures for personnel radiation protection shall be prepared consistent with the requirements of 10 CFR Part 20 and shall be approved, maintained, and adhered to for all operations involving personnel radiation exposure. 6.12 HIGH RADIATION AREA As provided in paragraph 20.1601(c) of 10 CFR Part 20, the following controls shall be applied to high radiation areas in place of the controls required by paragraph 20.1601(a) and (b) of 10 CFR Part 20: 6.12.1 HiQh Radiation Areas with Dose Rates Not Exceeding 1.0 rem/hour at 30 Centimeters from the Radiation Source or from any Surface Penetrated by the Radiation

a. Each entryway to such an area shall be barricaded and conspicuously posted as a high radiation area. Such barricades may be opened as necessary to permit entry or exit of personnel or equipment.

b. Access to, and activities in, each such area shall be controlled by means of a Radiation Work Permit (RWP) or equivalent that includes specification of radiation dose rates in the immediate work area(s) and other appropriate radiation protection equipment and measures.

c. Individuals qualified in radiation protection procedures and personnel continuously escorted by such individuals may be exempted from the requirement for an RWP or equivalent while performing their assigned duties provided that they are otherwise following plant radiation protection procedures for entry to, exit from, and work in such areas.

d. Each individual or group entering such an area shall possess:

1. A radiation monitoring device that continuously displays radiation dose rates in the area, or MILLSTONE - UNIT 3 6-21 Amendment No. 7f, f9, 09, h 0911 J90, i77 Zj,2152X

ADMINISTRATIVE CONTROLS 6.12 HIGH RADIATION AREA (cont.)

2. A radiation monitoring device that continuously integrates the radiation dose rates in the area and alarms when the device's dose alarm setpoint is reached, with an appropriate alarm setpoint, or

3. A radiation monitoring device that continuously transmits dose rate and cumulative dose information to a remote receiver monitored by radiation protection personnel responsible for controlling personnel radiation exposure within the area, or

4. A self-reading dosimeter (e.g., pocket ionization chamber or electronic dosimeter) and, (i) Be under the surveillance, as specified in the RWP or equivalent, while in the area, of an individual qualified in radiation protection procedures, equipped with a radiation monitoring device that continuously displays radiation dose rates in the area; who is responsible for controlling personnel exposure within the area, or (ii) Be under the surveillance as specified in the RWP or equivalent, while in the area, by means of closed circuit television, of personnel qualified in radiation protection procedures, responsible for controlling personnel radiation exposure in the area, and with the means to communicate with individuals in the area who are covered by such surveillance.

e. Except for individuals qualified in radiation protection procedures, or personnel continuously escorted by such individuals, entry into such areas shall be made only after dose rates in the area have been determined and entry personnel are knowledgeable of them. These continuously escorted personnel will receive a pre-job briefing prior to entry into such areas. This dose rate determination, knowledge, and pre-job briefing does not require documentation prior to initial entry.

6.12.2 High Radiation Areas with Dose Rates Greater than 1.0 rem/hour at 30 Centimeters from the Radiation Source or from any Surface Penetrated by the Radiation, but less than 500 rads/hour at 1 Meter from the Radiation Source or from any Surface Penetrated by the Radiation

a. Each entryway to such an area shall be conspicuously posted as a high radiation area and shall be provided with a locked or continuously guarded door or gate that prevents unauthorized entry, and, in addition:

1. All such door and gate keys shall be maintained under the administrative control of the shift manager, radiation protection manager, or his or her designees, and

2. Doors and gates shall remain locked except during periods of personnel or equipment entry or exit.

b. Access to, and activities in,each such area shall be controlled by means of an RWP or equivalent that includes specification of MILLSTONE - UNIT 3 6-22 Amendment No. f?, gJ7, 215 0911 MAY 15 200

ADMINISTRATIVE CONTROLS 6.12 HIGH RADIATION AREA (cont.) radiation dose rates in the immediate work area(s) and other appropriate radiation protection equipment and measures.

c. Individuals qualified in radiation protection procedures may be exempted from the requirement for an RWP or equivalent while performing radiation surveys in such areas provided that they are otherwise following plant radiation protection procedures for entry to, exit from, and work in such areas.

d. Each individual group entering such an area shall possess:

1. A radiation monitoring device that continuously integrates the radiation dose rates in the area and alarms when the device's dose alarm setpoint is reached, with an appropriate alarm setpoint, or

2. A radiation monitoring device that continuously transmits dose rate and cumulative dose information to a remote receiver monitored by radiation protection personnel responsible for controlling personnel radiation exposure within the area with the means to communicate with and control every individual in the area, or

3. A self-reading dosimeter (e.g., pocket ionization chamber or electronic dosimeter) and, (i) Be under the surveillance, as specified in the RWP or equivalent, while in the area, of an individual qualified in radiation protection procedures, equipped with a radiation monitoring device that continuously displays radiation dose rates in the area; who is responsible for controlling personnel exposure within the area, or (ii) Be under the surveillance as specified in the RWP or equivalent, while in the area, by means of closed circuit television, of personnel qualified in radiation protection procedures, responsible for controlling personnel radiation exposure in the area, and with the means to communicate with and control every individual in the area.

4. In those cases where options (2)and (3), above, are impractical or determined to be inconsistent with the "As Low As is Reasonably Achievable" principle, a radiation monitoring device that continuously displays radiation dose rates in the area.

e. Except for individuals qualified in radiation protection procedures, or personnel continuously escorted by such individuals, entry into such areas shall be made only after dose rates in the area have been determined and entry personnel are knowledgeable of them. These continuously escorted personnel will receive a pre-job briefing prior to entry into such areas. This dose rate determination, knowledge, and pre-job briefing does not require documentation prior to initial entry.

f. Such individual areas that are within a larger area where no enclosure exists for the purpose of locking and where no enclosure can reasonably be constructed around the individual area need not be controlled by a locked door or gate, nor continuously guarded, but shall be barricaded, conspicuously posted, and a clearly visible flashing light shall be activated at the area as a warning device.

MILLSTONE - UNIT 3 6-23 Amendment No. fy, 77Z, 215 0911 u&J I K %M~

ADMINISTRATIVE CONTROLS 6.13 RADIOLOGICAL EFFLUENT MONITORING AND OFFSITE DOSE CALCULATION MANUAL (REMODCM)

a. The REMODCM shall contain the methodology And parameters used in the calculation of offsite doses resulting from radioactive gaseous and liquid effluents, in the calculation of gaseous and liquid effluent monitoring alarm and trip setpoints, and in the conduct of the radiological environmental program; and

b. The REMODCM shall also contain the radioactive effluent controls and radiological environmental monitoring activities and descriptions of the information that should be included in the Annual Radiological Environmental Operating, and Radioactive Effluent Release, reports required by Specification 6.9.1.3 and Specification 6.9.1.4.

Licensee initiated changes to the REMODCM:

a. Shall be documented and records of reviews performed shall be retained.

This documentation shall contain:

1) sufficient information to support the change(s) together with the appropriate analyses or evaluations justifying the change(s), and

2) a determination that the change(s) will maintain the level of radioactive effluent control required by 10 CFR 20.1302, 40 CFR Part 190, 10 CFR 50.36a, and Appendix I of 10 CFR 50, and not adversely impact the accuracy or reliability of effluent, dose, or setpoint calculations;

b. Shall become effective after review and acceptance by SORC and the approval of the designated officer; and

c. Shall be submitted to the Commission in the form of a complete, legible copy of the entire REMODCM as a part of or concurrent with the Radioactive Effluent Release Report for the period of the report in which any change in the REMODCM was made. Each change shall be identified by markings in the margin of the affected pages, clearly indicating the area of the page that was changed, and shall indicated the date (i.e., month and year) the change was implemented.

6.14 RADIOACTIVE WASTE TREATMENT Procedures for liquid and gaseous radioactive effluent discharges from the Unit shall be prepared, approved, maintained and adhered to for all operations involving offsite releases of radioactive effluents. These procedures shall specify the use of appropriate waste treatment systems utilizing the guidance provided in the REMODCM. The Solid Radioactive Waste Treatment System shall be operated in accordance with the Process Control Program to process wet radioactive wastes to meet shipping and burial ground requirements. MILLSTONE - UNIT 3 6-24 Amendment No. fp, of, Fl, JP, AgP, 0697 M7l, 71,188

ADMINISTRAT1VF CflNTRAI C 6.15 RADIOACTIVE EFFLUENT CONTROLS PROGRAM This program conforms to 10 CFR 50.36a for the control of radioactive effluents and for maintaining the doses to members of the public from radioactive effluents as low as reasonably achievable. The program shall be contained in the REMODCM, shall be implemented by procedures, and shall include remedial actions to be taken whenever the program limits are exceeded. The program shall include the following elements:

a. Limitations on the functional capability of radioactive liquid and gaseous monitoring instrumentation including surveillance tests and setpoint determination in accordance with the methodology in the REMODCM;

b. Limitations on the concentrations of radioactive material released in liquid effluents to unrestricted areas, conforming to ten times the concentration values in Appendix B, Table 2, Column 2 to 10 CFR 20.1001- I 20.2402;

c. Monitoring, sampling, and analysis of radioactive liquid and gaseous effluents in accordance with 10 CFR 20.1302 and with the methodology and parameters in the REMODCM;

d. Limitations on the annual and quart:erly doses or dose commitment to a member of the public from radioacitive materials in liquid effluents released from each unit to unrestri:fted areas, conforming to 10 CFR 50, Appendix I;

e. Determination of cumulative dose contributions from radioactive effluents I for the current calendar quarter and current calendar year in accordance with the methodology and parameters in the REMODCM at least every 31 days.

Determination of projected dose contributions from radioactive effluents in accordance with the methodology in the REMODCM at least every 31 days;

f. Limitations on the functional capability and use of the liquid and gaseous effluent treatment systems to ensure that appropriate portions of these systems are used to reduce releases of radioactivity when the projected doses in a period of 31 days would exceed 2% of the guidelines for the annual dose or dose commitment, conforming to 10 CFR 50, Appendix I;

g. Limitations on the dose rate resulting from radioactive material released in gaseous effluents from the site to areas at or beyond the site boundary shall be in accordance with the following:

1. For noble gases: a dose rate < 500 mrem/yr to the whole body and a dose rate < 3000 mrem/yr to the skin, and

2. For iodine-131, iodine-133, tritium, and all radionuclides in particulate form with half-lives greater than 8 days: a dose rate <

1500 mrem/yr to any organ;

h. Limitations on the annual and quarterly air doses resulting from noble gases released in gaseous effluents from each unit to areas beyond the site boundary, conforming to 10 CFR 50, Appendix I;

i. Limitations on the annual and quarterly doses to a member of the public from iodine-131, iodine-133, tritium, and all radionuclides in particulate form with half lives > 8 days in gaseous effluents released from each unit to areas beyond the site boundary, conforming to 10 CFR 50, Appendix 1; and MILLSTONE - UNIT 3 6-25 Amendment No. X??, 215 0915 UAV i w

ADMINISTRATIVE CONTROLS

j. Limitations on the annual dose or dose commitment to any member of the public, beyond the site boundary, due to releases of radioactivity and to radiation from uranium fuel cycle sources, conforming to 40 CFR 190.

I The provisions of Specification 4.0.2 and Specification 4.0.3 are applicable to the Radioactive Effluent Controls Program surveillance frequency. 6.16 RADIOLOGICAL ENVIRONMENTAL MONITORING PROGRAM A program shall be provided to monitor the radiation and radionuclides in the environs of the plant. The program shall provided (1) representative measurements of radioactivity in the highest potential exposure pathways, and (2) verification of the accuracy of the effluent monitoring program and modeling of environmental exposure pathways. The program shall (1) be contained in the REMODCM, (2) conform to the guidance of Appendix I to 10 CFR Part 50, and (3) include the following:

a. Monitoring, sampling, analysis, and reporting of radiation and radionuclides in the environment in accordance with the methodology and parameters in the REMODCM.

b. A Land Use Census to ensure that changes in the use of areas at and beyond the SITE BOUNDARY are identified and that modifications to the monitoring program are made if required by the results of this census, and

c. Participation in a Interlaboratory Comparison Program to ensure that independent checks on the precision and accuracy of the measurements of radioactive materials in environmental sample matrices are performed as part of the quality assurance program for environmental monitoring.

6.17 REACTOR COOLANT PUMP FLYWHEEL INSPECTION PROGRAM This program shall provide for the inspection of each reactor coolant pump flywheel by either qualified in-place UT examination over the volume from the inner bore of the flywheel to the circle of one-half the outer radius or a surface examination (magnetic particle testing and/or penetrant testing) of exposed surfaces defined by the volume of the disassembled flywheels at least once every 10 years. 6.18 TECHNICAL SPECIFICATIONS (TS) BASES CONTROL PROGRAM This program provides a means for processing changes to the Bases of these Technical Specifications:

a. Changes to the Bases of the TS shall be made under appropriate administrative controls and reviews.

b. Licensees may make changes to Bases without prior NRC approval provided the changes do not require either of the following:

1. A change in the TS incorporated in the license or

2. A change to updated FSAR or Bases that requires NRC approval pursuant to 10 CFR 50.59.

MILLSTONE - UNIT 3 6-26 Amendment No. 199, g0%, 717. 215 0915 MAY IL AX

ADMINISTRATIVE CONTROLS

c. The Bases Control Program shall contain provisions to ensure that the Bases are maintained consistent with the FSAR.

d. Proposed changes that meet the criteria of Specification 6.18.b above shall be reviewed and approved by the NRC prior to implementation.

Changes to the Bases implemented without prior NRC approval shall be provided to the NRC on a frequency consistent with 10 CFR 50.71(e). 6.19 COMPONENT CYCLIC OR TRANSIENT LIMIT This program provided controls to track the FSAR, Section 3.9N, cyclic and transient occurrences to ensure that components are maintained within the design limits. MILLSTONE - UNIT 3 6-27 Amendment No. 11. 215 0915 MAY 15 203}}