ML20082U377
| ML20082U377 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 12/08/1983 |
| From: | GENERAL PUBLIC UTILITIES CORP. |
| To: | |
| Shared Package | |
| ML20082U361 | List: |
| References | |
| NUDOCS 8312160323 | |
| Download: ML20082U377 (226) | |
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{{#Wiki_filter:.. _ _ _ _ ._ . . _ _ _ ._ TABLE OF CONTDITS PAGE
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Section 1 Definitions 1.1 Operable 1-1 i 1.2 Operating _ 1-1 1.3 Power Operation 1-1 1.4 Startup Mode 1-1 1.5 Run Mode 1-1 1.6 Shutdown Condition 1-1 1.7 Cold Shutdown ~1-2 1.t Place in Shutdown Condition 1-2 1.9 Place in Cold Shutdown Condition 1-2 1.10 Place in Isolated Condition 1-2 1.11 Refuel Mode 1-2 i > 1.12 Refueling Outage 1-2 1.13 Primary Containment Integrity 1-2 1.14 Secondary Containment Integrity 1-3 f 1.15 Deleted ,
.1-3 l 1.16 Rated Flux 1-3 1.17 Reactor Thermal Power-to-Water 1-3 4
1.18 Protective Instrumentation Logic Definitions 1-3 1.19 Instrumentation Surveillance Definitions ' 1-4 i 1.20 FDSAR 1-4 i i 1.21 Core Alteration 1 1.22 Minimum Critical Power Ratio ~. 1-4 1.23 Staggered Test Basis - 1-4 1.24 Surveillance Requirements. . 1 *1.25 Fire suppression Water System 1-5 0 i 1.' 8312160323 831208 PDR ADOCK 05000219 >
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.Section 2 Safety Limits and Limitina Safety Systems Settings 2.1 Safety Limit - Fuel Cladding Integrity 2-1 2.2 Safety Limit - Reactor Coolant System Pressure 2-6 2.3 Limiting Safety Systems Settings 2-0 Section 3 Limitina Conditions'for Operatien 3.0 Limiting Conditions for Operation (General) 3-1 3.1 Pentective Instrumentation 3-3 3.2 Reactivity Control 3-10 3.3 Reactor Coolant 3-20 3.4 Emergency Cooling 3-27 3.5 Containment 3-34 3.6 Radioactive Effluents 3-44 3.7 Auxiliary Electrical Power 3-52 3.8 Isolation Condenser 3-55 3.9 Refueling 3-57 3.10 Core Limits 3-60 3.11 (Not Used) 3.12 Fire Protection 3-67 3.13 Accident Monitoring Instrumentation 3-71 Section 4 Surveillance Requirements 4.1 Protective Instrumentation 4-1 4.2 Reactivity Control 4-5 11 t ; I l' L _ _ __ uu . . ..
TABLE CF CONTENTS PAGE 4.3 Reactor Coolant 4-9 4.4 Emergency Cooling 4-12 l 4.5 Containment 4-14 4.6 Radioactive Effluents 4-28 4.7 Auxiliary Electrical Power 4-33 4.8 Isolatien Condenser 4-35 4.9 Refueling 4-37 4.10 ECCS Related Core Limits 4-39 4.11 Sealed Source Contamination 4-41 + 4.12 Fire Protection , 4-42 4.13 Accident Monitoring Instrumentation 4-47 Section 5 Desian Features 5.1 Site e- 5-1 5.2 Containment 5-1 5.3 Auxiliary Equipment 5-1 Section 6 Administrative Centrols 6.1 Responsibility 6-1 6.2 Organization 6-1 6.3 Tacility Staff Qualifications '6-2 6.4 Training 6-4 6.5' Review and Audit 6-4 6.6 Reportable D:currence Action .6-9 6.7 Safety Limit Violation 6-10 6.8 Procedures 6-10 0 iii 4 'r
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TAELE OF COMTENTS - TABLCS Table 3.1.1 Protective Instrumentation Requirements Table 3.3.1 Primary Coolant System Pressure Isolation Valves Table 3.5.1 Safety Related Snubbers Table 3.5.2 Containment Isolation Valves Table 3.6.1 Dose Factors for Exposure to a Semi-Infinite Cloud of Noble Gases Table 3.6.2 Thyroid Dose Factors for Inhalation (Rii), Ground Plane Exposure (Rgi), and Vegetation Consumption (Rvi) Table 3.12.1 Fire Detection Instrumentation Table 3.12.2 Spray / Sprinkler Systems Table 3.12.3 Hose Stations Taele 3.12.4 Halen Systems Table 3.12.5 Hydrants and Hose Houses Table 3.13.1 Accident Monitoring Instrumentation Table 4.1.1 Minimum Check, Calibration & Test Frequency for Protective Instrumentation Table 4.1.2 Minimum Test Frequencies for Trip Systems Table 4.3.1 Examinatien Schedule of. Reactor Coolant System Table 4.3.2 Primary Coolant System Pressure Isolation Valves Table 4.13.1 Accident Monitoring Instrumentation Surveillance Requirements Tabic 6.5.1 Safety Review Responsibilities U y
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TABLE OF COMTENTS - FIGURES Figure 2.1.1 Fuel Cladding Integrity Safety Limit Figure 3.2.1 Sodium Pentaborate Solution Volume Ccncentration. Requirements Figure 3.2.2 Sodium n entaborate Solution Temperature Requirements Figure 3.3.1 Oyster Creek Huclear Generating Station Reactor Vessel Pressure / Temperature Limits For Up To Ten Effective Full Power Years of Core Operation Figure 3.5.1 Required Drywell To Torus Differential Pressure Figure 3.10.1 Maximum Allowable Average PLANAR Linear Heat Generation Rate (Five Loop Operation) Figure 3.10.2 Maximum Allowable Average PLANAR Linear Heat Generation Rate (Four Loop Operation) Figure 3.10.3 Axial MAPLHGR Multiplier Figure 4.1.1 Failure Versus Time In Service Figure 4.5.1 Maximum Allowable Pressure Drop (Inches of Hater) for HEPA Filter Figure 6.2.1 Crganization Chart GPU Nuclear Corporation Figure 6.2.2 Onsite Organization I P ?
SECTION 1 O DEFINITIONS The following frequently used terms are defined to aid in the uniform interpretation of the specifications. 1 1.1 OPERABLE-OPERABILITY I A system, subsystem, train, component, or device shall be OPERABLE or have OPERABILITY uhen it is capable of performing its specified function (s). Implicit in this definition shall be the assumption that I i all necessary attendent instrumentation, controls, normal and emergency electrical poner sources, cooling of seal Hater, 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). 1.2 OPERATING Operating means that a system or co=ponent is performing its required function. 1.3 POWER OPERATION Power operation is any operation when the reactor is in the startup mode or run mode except when primary containment integrity is not required. - 1.4 STARTUP MODE The reactor is in the startup mode when the reactor mode switch is in the startup mode position. In this mode, the reactor protection system scram trips initiated by condenser low vacuum and main steam line isolation valve closure are bypassed when reactor pressure is less than 600 psig; the low pressure main s.teamline isolation valve closure is bypassed; the IRM trips for rod block and scram are operable; and the SRM trips for rod block are operable. 1.5 RUN MODE The reactor is in the run mode when the reactor mode switch is in the run mode position. In this mode, the reactor protection system is energized with APRM protection and the control rod .Hithdrawal interlocks are in service. 1.6 SHUTDOWN CONDITION
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The reactor is in a shutdown condition when the reactor mode switch is in the shutdown mode position and there is fuel in the reactor vessel. In this condition,.the reactor is suberitical, a control rod block is - initiated, all operable control rods are fully inserted, and Specification 3.2-A is met. b ' 1.1-1
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1.7 COLD SHUTDONN The reactor is at cold shutdown when the mode sHitCh is in the shutdown mode position, there is fuel in the reactor vessel, all operable control rods are fully . inserted, and the reacter coolant system maintained at less than 212 8F and vented. 1.8 PLACE IN SHUTDOWN CONDITION Proceed Hith and maintain an uninterrupted normal plant shutdown operation until the shutdown condition is met. 1.9 PLACE IN COLD SHUTDOWN CONDITION Proceed with and maintain an uninterrupted normal plant shutdown operation until the cold shutdoun condition is met. 1.10 PLACE IN ISOLATED CONDITION Proceed with and maintain an uninterrupted normal isolation of the reactor from the turbine condenser system including closure of the main steam isolation valves. 1.11 REFUEL MODE - The reactor is in the refuel mode when the reactor mode switch is in the refuel mode position and there is fuel in the reactor vessel. In this mode the refueling platform interlocks are in operation. 1.12 REFUELING OUTAGE For the purpose of designating frequency of testing and surveil ~ance, a refueling outage shall mean a regularly scheduled refueling outage; however, where such outages occur within 8 months of the end of the previous refueling outage, the test or surveillance need not be performed until the next regularly scheduled outage. Following the first refueling outage, the time betHeen successive tests or surveillance shall not exceed 20 months.* 1.13 PRIMARY CONTAINMENT INTEGRITY Primary containment integrity means that the drywell and adsorption chamber are closed and all of the following conditions are satisfied: A. All non-automatic primary containment isolation valves Hhich are not required to be open for plant operation are closed. B. At least one door in the airlock is closed and sealed. C. All automatic containment isolation valves specified in Table 3.5.2 are operable or are secured in the closed position. C D. All blind flanges and manHays are closed. I
*The time between successive tests or surveillance shall not exceed 30 months prier to the cycle 10 refueling outage only 1.1-2
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1.14 SECONDARY CONTAINMENT INTEGRITY Secondary containment integrity means that the reactor building is ~ closed and the following conditions are met: O A. At least one door at each access opening is clos?d. B. The standby gas treatment system is operable. C. !J1 reactor building ventilation system automatic isolation valves are operable or are secured in the closed position. 1.15 (DELETED) 1.1G RATED FLUX Rated flux is the neutron flux that corresponds to a steady state power level of 1930 MHT. The use of the term 100 percent also refers to the 1930 thermal megawatt power level. 1.17 REACTOR THERMAL POWER-TO-WATER Reactor thermal power-to-water is the sum of (1) the instantaneous integral over the entire fuel clad outer surface of the product of heat transfer area increment and position dependent heat flux and (2) the instantaneous rate of energy deposition by neutron and gamma reactions in all ~ the water and core .co=ponents except fuel rods -in _the cylindrical volume defined by the active core . height and the inner-surface of the core shroud. 1.18 PROTECTIVE INSTRUMENTATION LOG 1C DEFINITIONS A. Instrument Channel An instrument channel. means an arrangement of a sensor and auxiliary equipmsnt required to generate and transmit to a trip system a ' single trip signal related to the plant parameter monitored by.that-instrument. channel. B. Trio System A trip system means an arrangement of instrument channel trip signals-and auxiliary equipment required to initiate.- action 'to -accomplish a protective trip function.' A trip -system may . require one or more instrument channe.1 trip signals related to one or more plant parameters - in order to initiate trip . system action. . Initiation of protective action may require .the tripping. of. - a . single trip . system f(e.g.,. ' initiation- of a core spray loop, a containment spray loop, automatic depressurization, isolation of.an isolation condenser, offgas syrtem isolation,- reactor building isolation, standby gas treatment and rod block).or the coincident tripping of two. trip systems (e.g., initiation of scram, isolation condenser, reactor isolation,' Land primary . _ containment isolation). - 1.1-3
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- 1.19 INSTRUhENTATTON SURuEILLANCE DEFINITIONS A. Channel Check A qualitative determination of acceptable operability by observation of channel behavior during operation. This determination shall include, Hhere possible, comparison of the channel with other independent channels measuring the same variable.
B. Channel Test Injection of a simulated signal into the channel to verify its proper response includin,q, where applicable, alarm and/or trip initiating action. C. Channel Calibration Adjustment of channel output such that it responds, with acceptable range and accuracy, to known values of the parameter which the charael measures. Calibration shall encompass the entire chsnnel, including equipment actuation, alarm or trip. 1.20 FDSAR Oyster Creek Unit No. 1 Facility Description and Safety Analysis Repert as a= ended by revised pages and figure changes contained in Amendments 14,31 and 45. 1.21 CCREJLTERATION A core alteration is the addition, removal, relocation or other manual movement of fuel or controls in the reactor core. Control red movement with the control red drive hydraulic system is not defined as a core alteration. 1.22 MINIMUM CRITICAL POWER RATIO The minimum critical power rstio is the ratio of that power in a fuel assemoIy which is calculated to cause some point in that assembly to experience boiling transition to the actual assembly operating power. 1.23 STAGGERED TEST BASIS A Staggered Tes*. 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. B. The testing of one system, subsystem, train or other designated l component at the beginning of each subinterval. - I 1.1-4
1.24 SURVEILLANCE REGUIREMENTS are requirements relating to test,
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Surveillance requirements fm. calibration, er inspection to assure that the necessary quality cf , ( ) systems and components is maintained, that facility operation Hill be
'U Hithin the safety limits, and that the limiting conditions of operation Hill be met. Each surveillance requirement shall be performed within the specified time interval with:
*A. A maximum allowable extension not to exceed- 25% of the surveillance interval.
*B. total maximum combined interval time for uny .3 consecutive surveillance intervals not to exceed 3.25 times the specified surveillance interval.
Surveillance requirements for systems and components are applicable only during the modes of operation fcr which the systems or components. are required to be operable, unless otherwise stated in the specification. 1.25 FIRE SUPPRESSION MATER SYSTEM A FIRE SUPPRESSION MATER SYSTEM shall consist of: a water source; pump; and distribution piping with associated sectionalizing control or isolation valves. Such valves shall include yard hydrant curb valves, and the first valve ahead of the Hater flow alarm device on each sprinkler, hose standpipe or spray system riser. D
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SECTION 2 SAFETY LIMITS AMD LIMITING SAFETY SYSTEM SETTINGS 2.1 SAFETY LIMIT - FUEL CLADDING INTEGRITY Applicebility: Applies to the interrelated variables associated Hith fuel thermal behavior. Obiective: To establish limits on the important thermal hydraulic variables to assure the integrity of the fuel cladding. Specifications: A. When the reacter pressure is greater than 600 psia, the combination of reactor core flow and reactor thermal power to Hater shall not exceed the limit shown on Figure 2.1.1. for any fuel type. A.1 Figure 2.1.1. applies -directly.Hhen the total peaking factor is less than or equal to the following: Fuel Type IIIF
- a. Axial peak at core midplane or belon of ,,2.74 '
'b. Axial peak above core midplane of 52.50 For 8 x 8 Fuel
- a. Axial peak at core midplane er below of 2.78
- b. Axial peak above midplane of 2.61 i A.2 For total peaking factors greater than those specified in Specification 2.1.A.1, the safety limit is reduced by the following:
SL = slo x(PFo/PF) where: SL = reduced safety limit slo = safety limit from figure 2.1.1. PFo= peaking factor specified in Specification 2.1.A.1 PF = actual peaking factor-- B. When the reactor -pressure is.less than'600 psia or reactor' l floH is less than 10 percent of rated, the' reactor thermal power shall not exceed 354 MHt. '- C. The neutron flux = shall not exceed its scram setting for longer than'1.75 seconds. O 2.1 .
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D. During c11 modes of reactor operation with irradiated fuel in the reactor vessel, the Hater level shall not be less than 4'-8" above the top of the normal active fuel =ene. E. The existence of a minimum critical power ratio (MCPR) less than 1.32 for 7 x 7 fuel and 1.34 for 8 x 8 fuel shall constitute violation of the fuel cladding integrity safety limit. F. During all modes of operation except when the reactor head is off and the reactor is flooded to a level above the main steam nozzles, at least two (2) recirculation loop suction valves and their associated discharge valves Hill be in the full open position. - Bases: The fuel cladding represents one of the primary physical barriers which separate radioactive ~ material from the environs- The integrity of this cladding barrier is related to its relative freedom from perforations or cracking. Although some corrosion or use-related cracking may occur during the life of the cladding, fission product migration from this source is incrementally cumulative, continuously measurable and tolerable. Fuel cladding perforations, however, could result from thermal effects if reactor operation is significantly above design conditions and the associated protection system setpoint. While fission product migration from cladding perforation is just as measurable as that from use-related cracking, the thermally-caused cladding perferations signal a threshold, beyond which still greater thermal conditions may cause gross rather then incremental cladding deterioration. Therefore, the fuel cladding safety limit is defined in terms of the reactor operating conditions which may result in cladding perforation. A critical heat flux occurrence results in a decrease in heat transferred from the clad ane., therefore, high clad temperatures and the possibility of clad failure. However, the existence of a critical heat flux occurrence is not a directly observable parameter in an operating reactor. Furthermore, the critical heat flux correlatica data Hhich relates observable parameters to the critical heat flux magnitude is statistical in nature. The margin to boiling transition is calculated from plant operating para =eters such as core pressure, core flow, feedwater temperature, core power, and core power distribution. The margin for each fuel assembly is characterized by the critical power ratio (CPR) Which is the ratio of the bundle power which would produce onset of transition boiling divided by the actual bundle poHer. The minimum value of this ratio for any bundle in the core is the minimum critical power ratio (MCPR)(10). The safety limit curves shown in Figura 2.1.1. represent conditions which assure .th better than 95 percent confidence a - 95 percent probability of avoiding a critical heat flux occurrence. The critical power value was determined using the design basis critical power correlation given in Reference 1. The l operating range Hith MCPR greater than 1.32 for 7 x 7 fuel and l l 1.34 for 8 x 8 fuel is below and to the right of these curves.
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The design basis critical het flu:c correlation is based on an interrelationship of reactor coolant flow and steam quality. Steam quality is determined by reactor power, pressure, and coolant inlet enthalpy Hhich in turn is a function of feedwater temperature and Hater level. This correlation is based upon-d experimental data taken over the entire pressure range of interest in a BWR, and the correlating line was determined by the statistical mean of the experimental data. l Curves are presented for two different pressures in Figures 2.1.1. I The upper curve is based on nominal operating pressure of 1035 psia. The lower curve is based on a pressure of 1250 psia. In no case is reactor pressure ever expected to c:cceed 1250 psia because of protection system settings Hell beloH this value and, therefore, the curves Hill cover all operating conditions with interpolation. For pressures between 600 psia (the lower end of the critical heat flux correlation data) and 1035 psia, the upper curve is applicable with increased margin. The power shape used in the calculation of Figure 2.1.1 is given in Table 3.2 of Reference 10 for a peak to average power of 1.5 Hith a peak location at the core midplane (X/L = 0.5). Table 3.2 further shows an axial power shape with an axial peak of the same magnitude but with a peak location above the core midplane (X/L = 0.65). These power shapes result in total peaking factors for each fuel type as shown in Specification 2.1.A.1. The total peaking factor for each fuel type is to be less than that specified in Section 1.1.A.1 at rated power. When operating belon rated power with higher peaking factors as during control rod manipulation or near end of core life, applicability of the safety limit is assured by applying the reduction factors specified in 2.1.A.2. The feedwater temperature assumed was the maximum design temperature output of the feedwater heaters at the given pressures and flows (e.g., 334"F at 1035 psia and 100% floH) . For any lower feedwater temperature, subcooling is increased and the curves provide increased margin. The water level assumed in the calculations was ten inches.beloH the reactor loH Hater level scram point (10'-7" above the top of the active fuel), which is the location of the bottom of the steam-separator skirts. Of course, the reactor _could not'be operated in this condition. As long as the water level is above this point, the safety limit curves are applicable. As long as the water-level is above the bottom of the steam separator skirts, the amount of carryunder would not be increased and the core inlet enthalpy would not be influenced. The values of the parameters involved. in Figure 2.1.1 can be determined from information 'available in 1the control room. Reactor pressure and flow' are recorded- and -the APRM in-core - nuclear instrumentation is calibrated in terms of percent power. The range in pressure used for Specification 2.1.A in~ the calculation of the fuel cladding integrity safety limit is from 600 to 1250; psia. -Specification 2.1.B provides a requirement on + L') 2.1-3
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power 1:vs1 when operating belon 600 psia or 10% flow. In general, Specification 2.1.B will only be applicable during startup or shutdown of the plant. A review of all the applicable low pressure and low flow data (6,7) has shown the lowest data point for transition boiling to. have a heat flux of 144,000 BTU /hr-ft2. To insure applicablility to the BWR fuel rod geometry, and provide a margin, a factor of one-half was used, giving a critical heat flux of 72,000 BTU /hr-ft2. This is equivalent to a core average power of 354 MHt (18.3% of rated). This value is applicable to ambient pressure and no flow conditions. For any greater pressure or flow conditions, there is increased margin. During transient operation, the heat flux (thermal power-to-Hater) would lag behind the neutron flux due to the inherent heat transfer time constant of the fuel of 8-9 seconds. Also, the limiting safety system scram settings are at values which Hill not allow the reactor to be operated above the safety limit during normal operation or during other plant operating situations which have been analyzed in detail (2,3,4,8,9,10). If the scram occurs such that the neutron flux dwell time above the limiting, safety system setting is less than 1.75 seconds, the safety limit will not be exceeded for normal turbine or generator trips, which are the most severe normal operating transients expected. Following a- turbine or generator trip, if it is determined that the bypass system malfunctioned, analysis of plant data Hill be used to ascertain if the safety limit has been exceeded, according to Specification 2.1.A. The dwell time of 1.75 seconds in Specification 2.1.C provides increased margin for less severe power transients. Should a power transient occur, the event recorder would show the time interval the neutron flux is over its scram setting. When the event recorder is out of service, a safety limit violation Hill be assumed if the neutron flux exceeds the scram setting and control red scram does not occur. The event recorder shall be returned to an operable condition as soon as practical. If reactor Hater level should drop beloH the top of the active fuel, the ability to cool the core is reduced. This reduction in core cooling capability could lead to elevated. cladding temperatures and clad perforation. Hith a water level above the top of the active fuel, adequate cooling is maintained and the decay heat can easily be acco=modated. The lowest point at which the Water level can presently be l monitored is 4'-8" above the top of the active fuel. Although the I lowest reactor water level limit which ensures adequate core cooling is the top of the active fuel, the safety limit has been established at 4'-8" to provide a point which con be monitored. . Specification F assures that an adequate flow path exists from the annular space, between the pressure vessel wall and the core shroud, to the core region. This provides for good communication between these areas, thus assuring that reactor water level 2.1-4 l ls. m _ gj.9 g .m
instrument readings are truly indicative of the Hater level in th2 core region. . References (1) XN-75-34, Revision 1, The XN-2 Critical Power Correlation, Exxon Nuclear Company, Inc. , August 1,1975. (2) FDSAR, Volume I, Section 1.5-6. (3) Licensing Application Amendment 28, Guestion III.A-12. (4) Licensing Application Amendment 32, Cuestion 13. (5) FDSAR, Volume I, Section SII-7.3. (6) E. Janssen, "Multired Burnout at Low Pressure", ASME Paper 62-HT-26, August 1962. (7) K.H. Becker, " Burnout Conditions for Flow of Boiling Hater in Vertical Red Clusters", AE-74 (Stockholm, Sweden). May 1962. (8) Licensing Application Amendment 55, Sections 4. _ (9) Licensing Application Amendment 65, Sections B.IV, B.VIII, B.XI (10) Licensing Application Amendment 76 (Supplement No. 4). a (11) Deleted i O i O 2.1-5 u j l
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2.2 SAFETY LIMIT - REACTOR COOLANT SYSTEM PRESSURE Applicsbility: Applies to the limit on reactor coolant system pressure. Obiective: Preserve the integrity of the reactor coolant system. Specification: The reactor coolant system pressure shall not exceed 1375 psig whenever irradiated fuel is in the reactor vessel. Bases: The reactor coolant system (1) represents an important barrier in the prevention of the uncontrolled release of fission products. It is essential that the integrity of this system be protected by establishing a pressure limit to be observed whenever there is irradiated fuel in the reactor vessel. The pressure safety limi+;- of 1375 psig was derived from the design pressures of the reactor pressure vessel, coolant piping and isolation condenser. The respective design pressures are 1250 psig at 575"F, 1200 psig at 570"F and 1250 psig at 575"F. The pressure safety limit was chosen as the lower of the pressure transients permitted by the applicable design codes: ASME Boiler and Pressure Vessel Code Section I for the pressure vessel, ASME Boiler and Pressure Vessel Ccde Section III for the isolation condenser and the ASA Piping Code Section B31.1 for the reactor coolant system piping. The ASME Code permits pressure transients up to 10% over the design pressure (110% x 1250 = 1375 psig) and the ASA Code permits pressure transients up to 15% over the design pressure (115% x 1200 = 1380 psig). The design basis for the reactor pressure vessel makes evident the substantial margin of protection against failure at the safety pressure limit of 1375 psig. The vessel has been designed for a general membranc stress no greater than 20,000 psi at an internal pressure of 1250 psig and temperature of 575"F; this is more than a factor of 2 below the yield strength of 42,300 psi at this temperature. At the pressure limit of 1375 psig, the general membrane stress increases to 22,000 psi, still almost a factor of 2 below the yield strength. The reactor coolant system piping provides a comparable margin of protection at the established pressure safety limit. The normal operating pressure of the reactor coolant system is 1020 psig. An over-pressurization analysis (2) is performed each cycle to assure the pressure safety limit is not exceeded. The - reactor fuel cladding can withstand pressures up to the safety limit, 1375 psig, without collapsing (3). Finally, reactor system pressure is continously monitored in the control room during reactor operation on the 1600 psi full scale pressure recorder 2.2-1 C l ls m
with an error of less than 1% and a recorder time response of one second. References 4 (1) FDSAR, Volume I, Section IV. l (2) License Application, Amendment 76. (3) FDSAR, Volume I, Section III-2.3.3. l , l l a - l i i 1 1 i i 4 4 b f 4 'l 1 i 4 i J t
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2.3 LIMITING SAFETY SYSTEM SETTINGS Applicability: Applies to trip settings on automatic protective devices related to variables on which safety limits have been placed. Obiective:
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To provide automatic corrective action to prevent the safety limits from being exceeded. Specification: Limiting safety system settings shall be as folloHs: FUNCTION LIMITING SAFETY SYSTEM SETTINGS
- 1) Neutron Flux, Scram a) APRM For recirculation floH, H less than or equal to 61.0E6 lb/hr:
less than or equal to ((1.34E-6) H + 34.0) percent of rated neutron flux when total peaking factors in all fuel types are less than or equal to those in Specification 2.1.A.1, or The lowest value of: less than or equal to ((1.34E-6) H + 34.0) (PFo/PF) percent of rated neutron flux from among those calculations for each fuel type with total peaking factors, PF greater than Pro, Hhere Pro = peaking factor in Specification 2.1.A.1 For recirculation floH, H greater than 61.0E6 lb/hr: ! less than or equal to 115.7 percent I of rated neutron flux when total peaking factors in all fuel types are less than or equal to those in Specification 2.1.A.1, or ! The loHest Value of:
- 1ess than or eg'!al to 115.7 (Pro /PF)
. percent of ret.v d neutron flux from arong those calctilations for each fuel type with total peaking factors 2.3-1 - c I l'
I PF graater than PFo, Hhere PFo = peaking factor in Specification 2.1.A.1. b) IRM less than or equal to 15 percent of l rated neutron flux l
- 2) Neutron Flux, Control
! Rod Block j a) For recirculation flow, H less than or equal to 61.0E6 lb/hr: less than or equal to ((1.34E-6) H + 24.3)
. percent of rated neutron flux when total peaking factors in all fuel types are less than or equal to those in Specification 2.1.A.1, or The lowest value of: ,
less than or equal to-((1.34E-6) H + 24.3) (PFo/PF) percent of rated neutron flux from among those calculated for each fuel type with total
' peaking factors, PF greater than PFo, where Pro = peaking factor in greater-than Specification 2.1.A.1 For recirculation flow, H greater than !
61.0E6 lb/hr: less than or equal to 106 percent of rated neutron flux when total-
= peaking factors in all fuel types are less than or equal to those in. -{
Specification 2.1.A.1, or. 1 The lowest value of: less than or equal to 106 (PFo/PF) percent of rated neutron flux from among those calculated for each fuel type with total peaking factors, PF greater than Pro, Where PFo = peaking factor in Specification 2.1.A.1-
- 3) Reactor High Pressure, f' Scram less than or equal to 1060_psig.
- 4) ' Reactor High Pressure, 2 valves less than or equal to 1070 psig Relief Valves Initiation 3 valves less than or. equal to 1090 psig-
. 5) Reactor High Pressure, . .
l Isolation Condenser: 1060 psig Hith time delay less than or Initiation- ' equal to 15. seconds
- 6) Reactor High Pressure,. 4 a 1212 psig O 2.3 -
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Safety Vsive Initiation 4 a 1221 psig plus or minus 12 psi 4 a 1230 psig 4 a 1239 psig
- 7) Low Pressure Main Steam greater than or equal to 825 psig .
Line, MSIV Closure
- 8) Main Steam Line Isolation less than or equal to 10% Valve Valve Closure, Scram Closure from full open
- 9) Reactor Lou Hater Level, greater than or equal to li' 5" above Scram the top of the active fuel as indicated under normal operating conditions
- 10) Reactor Low-Low Hater Level, greater than or equal to 7' 2" above Main Steam Line Isolation the top of the active fuel as indicated Valve Closure, under normal operating conditions
- 11) Reactor Low-Lou Hater Level, greater than or equal to 7' 2" Core Spray Initiation above the top of the active fuel
- 12) Reactor Low-Lou Hater Level, greater than or equal to 7' 2" above Isolation Condenser the top of the active fuel with time Initiation delay less than or equal to 3 seconds
- 13) Turbine Trip Scram 10 percent turbine stop valve closure from full open
- 14) Generator Load Rejection Initiate upon loss of oil pressure from Scram turbine acceleration relay,,
a- . Bases: Safety limits have been established in Specifications 2.1 and 2.2 to protect the integrity of the fuel cladding and reactor coolant system barriers. Automatic protective devices have been provided in the plant design to take corrective action to prevent the _ safety limits from being exceeded in normal operation or operational transients caused by reasonable expected single operator error or, equip =ent malfunction. This Specification established the trip settings for these automatic protection devices. The Average Power Range Monitor, APRM (1), trip setting has been cstablished to assure never reaching the fuel cladding integrity safety limit. The APRM system responds to changes in neutron flux. However, near rated thermal power the APRM is calibrated, using a plant heat balance, so that the neutron flux that is-sensed is read out as percent of rated thermal power. For slow maneuvers, those where core thermal power, surface heat flux, and the power transferred to the water follow the neutron flux, the APRM will read reactor thermal power. For fast transients, the neutron flux will lead the poker transferred from the cladding to - the water due to the effect of the fuel time constant. Therefore, when the neutron flux increases to the scram setting, the percent increase in heat flux and power transferred to the water will be l 1ess than the percent increase in neutron flux. 1 2.3-3
'I
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7 !" Th2 APRM . trip' 'satting .will be varitd t.utomatically with recirculation flow with the trip setting at rated flow 61.0E6 lb/hr or greater being 115.7% of rated neutron flux. Based on a i i complete evaluation of' the reactor dynamic performance during ,O normal operation as well as' expected maneuvers and the Various mechanical failures, it was concluded that ' sufficient protection is provided by the simple fixed point scram settings so that all ^ thermal limits are satisfied (3, 4, 10). However, in response to expressed beliefs (5)- that variation.'of. APRM flux scram with recirculation flow is a prudent measure to ensure safe plant operation during the design confirmation phase of plant. operation, the scram setting will be' varied with recirculation flow. If ' during the power demonstration run the design analyses are-confirmed with respect to nuclear behavior ~ characteristics, the automatic flow Diased scram could be replaced with a fixed scram , setting. Lowering the set point of. the APRM scram would result in more
, margin between normal operation and the cafety limit; however, j lowering the set point could also result in spurious scrams. Fe example, there are transients which will occur during . operation,- J such as those due to testing turbine bypass valves or pressure set point changes, which result in insignificant changes (less--than 1%) in the power transferred from the cladcing to the water, but . :
for which tha neutron flux rises 10-15% (3). Calculations which include uncertainties in the heat balance show L that the setting accuracy is plus or minus 2.5%. in the 65-100%. power range (6). A turbine trip without byp3ss analyzed assuming a 125% scram showed no appreciable change.in results from a 123% scram analysis (3). In additon, if the errors are random, some APRH's will trip low, the net effect .being 'no change in the j transient results. Therefore, allowing for instrument calibration errors, the scram setting is adequate to prevent the safety . limit from being exceeded and yet high enough to reduce the number.of spurious scrams. 1
-For slow powar rises in the power range which might-be produced by.
- control rod withdrawal, the power is limited by'the APRM control
[ rod block (1), whose set ~ point. is varied automatically with
- recirculation flow.- At conditions of rated flow or" greater, Lthe
' rod block is initiated at 106 percent of rated power. For the ! single rod withdrawal error this setting causes rod -block' before MCPR reaches 1.32 for 7 x 7_ fuel and 1.34 for 8 x 8 fuel (13).- ! For operation along the flow control line and at power levels less i than 61% of rated the inadvertent withdrawal of a single control l rod does not result in MCPR = 1.32 for.7..x 7 fuel and 1.34 for 8 x > 8 fuel even assuming there is no control rod block action'(7).
The safety curve of Figure 2.1.1-is based on total peaking factors of 2.74 for fuel types IIIE and IIIF: 2.80 for fuel type II; fand 2.78 for 8 M' 8 fuel. ~ These curves are to be adjusted downward (by ' - the equations shown in Specificationc 2.1.A.2) 'in- the . event _ of higher l peaking -factors. Also to ensure MCPR's greater than 1.32 - for 7 x 7 fuel and 1.34 for 8lx 8 fuel during expected transients,- - neutron flux, ; scram and~ control'. rod ' block ysettings 'must be-correspondingly reduced. The equations describing these setpoints :
\ !: l2.3-4~ , q s
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34 . g > n .
maks ellowanca for peaking factors greatir than 2.74, 2.80, or 2.78 respectively for the fuel types listed above by reducing the setpoints at rated neutron flux by the ratio of PFo to PF. For operation in the startup mode phile the reactor is at low pressure, the IRM scram setting of 15% of rated power provides 22% thermal margin betHeen the maximum poHer and the safety limit, 18.3% of rated. The margin is adequate to accommodate anticipated maneuvers associated Hith poHer plant startup. There are a few possibic sources of rapid reactivity input to the system in the low power low flow condition. Effects of increasing pressure at zero or low void content are minor, cold Hater from sources available during startup is not much colder than that already in the system, temperature coefficients are small, and control rod patterns are constrained to be uniform by operating procedures backed up cy the rod north minimizer. N rth of individual rods is very low in a uniform rod pattern. Thus, of all possible sources of reactivity input, uniform control rod withdrawal is the most probable cause of significant power rise. Because the flux distribution associated Hith uniform rod withdrawals does not involve high local peaks, and because several rods must be moved to change power oy a significant percentage of rated, the rate of power rise. is very slow. Generally the heat flux is in near equilibrium with the fission rate. In an assumed uniform rod withdrawal approach to the scram level, the rate of power rise is no more than five percent of rated per minute, and the IRM system would be more than adequate to assure a scram before the power could exceed the safety limit. The IRM scram remains active until the mode switch is placed in the run position at which time the trip becomes a coincident IRM upscale, APRM downscale scram. The Reactor Protection System is designed such that reactor pressure must be above 825 psig to successfully transfer into the RUM mode, thus assuring protection for the fuel cladding safety limit. The settings on the reactor high pressure scram, anticipatory scrams, reactor coolant system relief valves and isolation condenser have been established to assure never reaching the reactor coolant system pressure safety limit as well as assuring the system pressure does not exceed the vange of the fuel cladding integrity safety limit. In addition, the APRM neutron flux scram and the turbine bypass system also provide protection for these safety limits, e.g., turbine trip and loss of electrical load transients (8). In addition to preventing power operation above 1060 psig, the pressure scram backs up the other scrams for these : transients and other steam line isolation type transients. With l the addition cf the anticipatory scrams, the transient analysis for operation at 1930 MWt shows that the turbine trip Hith failure of the bypass system transient is the worst case transient with respect to peak pressure. Analysis of this transient shows that the relief valves limit the peak pressure Hell below the 1250 psig range of applicability of the fuel cladding integrity safety limit - and the 1375 psig reactor coolant system pressure safety limit. Actuation of the isolation condenser during these transients removes the reactor decay heat without further loss of reactor coolant thus protecting the reactor water level safety limit. 2.3-5
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. : a
Thi<rtsetor coolant system safety valves offer yzt gnother protective feature for the reactor coolant system pressure safety limit --since these valves are sized assuming no credit for other pressure relieving devices. In compliance with Section I of the O ASME Boiler and' Pressure Vessel Code, the safety valves must be set to open at a pressure no higher than 103% of design pressure, and they must limit the reactor pressure to no more than 110%.of design pressure. The safety valves are sized according to the code for a condition of turbine stop valve closure while operating at 1930 hM(t), followed by (1) a delay of all scrams, (2) failure of the turbine bypass valves to .open, and (3) failure of the 4 isolation condensers and relief valves to operate. Under these , conditions, a total of 16 safety valves are required to turn the pressure transient. For analysis purposes, the void reactivity , coefficient was also pessimistically increased by 50%, i.e., a void coefficient 1.5 times normal. With the safety valves set as ; specified herein the maximum vessel pressure -(at the bottom of 'the pressure vessel) would be about 1301 psig (9); maximum pressure at the lowest- point in tne recirculation loop is approximately 1315 1 psig which is 60 psi below the safety limit. The ASME B&PV Code. allows a plus or minus 1% of working pressure (1250 psig)' variation in the pop point of the valves. This variation is recognized in Specification 4.3. The low pressure isolation of the main steam lines at 825 psig was i provided to give protection against fast reactor depressurization and the resultir.g rapid cool-down of the vessel. Advantage was taken of the scram feature which occurs when the main steam line-
- p. isolation valves are closed to provide for reactor shutdown so 4
that high power operation at low reactor pressure does not occur, p thus providing protection for the fuel cladding integrity safety limit. Operatien of the reactor at- pressures lower than 825 psig requires that the reactor mode switch be in the startup position where protection of the fuel cladding integrity safety ! limit is provided by the IRM high neutron flux scram. .Thus, the , i combination of - main steam line low. pressure isolation. and isolation valve closure scram assures the availability of neutron- ' flux scram protection over the entire range of applicability of the fuel cladding integrity safety . limit. In addition l'the 4 isolation valve closure scram anticipates the pressure and flux-transients which ioccur during normal or inadvertent isolation. valve closure. With the scrams set at 10% valve closure, there is'no increase in-neutron-flux and the. peak pressure is. limited to 1110.psig-(9). The low water -level trip setting of 11'5" above the top of the- - active fuel has been established to assure that the reactor is not. operated at a water level below that for which the fuel cladding - integrity safety limit is applicable. With the scram set at -this point, the generation of steam, and thus the loss of inventory, is stopped. For example, for a loss of. feedwater : -flow a . reactor " scram at the value indicated and isolation valve closure at the low-low water ~1evel set point results in more than 4 feet of water remaining above the core after isolation (11). < l
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During periods whin th3 reactor is shut down, decay hrat is present and adequate water level must be maintained to provide core cooling. Thus, the low-low level trip point of 7'2" above the core is provided to actuate the core spray system to provide cooling water should the level drop to this point. In additicn, the normal reactor feedwater system and control rod drive hydraulic system provide protection for the water level safety limit both when the reactor is operating at power or in the shutdown condition. The turbine stop valve (s) scram anticipates the pressure, neutron flux, heat flux increase caused by the rapid closure of the turbine stop valve (s) and failure of the turbine bypass system. With a scram setting of 10% of valve closure from full open and with a failure of the turbine bypass system at 1930 MHt, the peak pressure will remain well below the first safety valve setting and no thermal limits are approached (7,10). The generator load rejection scram is provided to anticipate the rapid increase in pressure and neutron flux resulting from fast closure of the turbine control valves to a load rejection and failure of the turbine bypass system. This scram is initiated by the loss of turbine acceleration relay oil pressure. The timing for this scram is almost identical to the turbine trip and the resultant peak pressure and MCHFR are essentially the same. References (1) FDSAR, Volume I, Section VII-4.2.4 (2) FDSAR, Volume I, Section I-5.6 (3) Licensing Application Amendment 28, Item III.A-12 (4) Licensing Application Amendment 32, Guestion 13 (5) Letters, Peter A. Morris, Director, Division of Reactor Licensing, USAEC to John E. Logan, Vice President, JCP&L Co., dated November 22, 1967 and January 9, 1968 (6) Licensing Application Amendment 11, Question V-9. (7) Licensing Application Amendment 76, Supplement No. 1. (8) Licensing Application Amendment 65, Section B.XI. (9) Licensing Application Amendment 69, Section III-D-5 (10) Licensing Application Amendment 65, Section B,IV. , 1 l (11) Licensing Application Amendment 65, Section B.IX. (12) Licensing Application Amendment 76, Supplement No. 3, Section 2.0 (13) Licensing Application Amendment 76, Supplement No. 4. 2.3-7
- 1 l'
SECTION 3 LIMITING CONDITIONS FOR OPERATION I , 3.0 LIMITING CONDITIONS FOR OPERATION (GENERAL) Applicability: Applies to all Limiting Conditions for Operation. Obiective: To perserve the single failure criterion for safety systems. Specifications: A. In the event Limiting Conditions for Operation (LCOs) and/or
- associated action requirements cannot be sotisfied because of circumstances in excess of those s? dressed in the specification, the unit shall be placed in COLD SHUTDOWN Hithin the following 30 hours unless corrective measures are completed that permit operation under the permissible action statements for the specified time interval as measured from initial discovery or until- the reactor is placed in a condition in which the specification is not applicable.
-Exceptions to the requirements shall be stated in the individual specifications.
B. When a system, subsystem, train, component or device is-O determined to be inoperable solely- because its emergency power source is inoperable, or solely because its normal power source is inoperable, it may be considered OPERABLE for the purpose of satisfying the' requirements of applicable LCOs., provided (1) its corresponding' normal, or emergency _ power source is OPERABLE; and (2) all of its redundant . system (s), subsystem (s), train (s), . component (s), and device (s) 'are OPERABLE, or likewise satisfy the requirements of this specification. Unless both conditions (1) and (2) are satisfied, the unit shall be placed in COLD SHUTDOWN-Hithin the following 30 hours or within the time specified in-the applicable specification. This specification is not applicable in COLD SHUTDOWN or the-REFUEL MODE. Bases: Specification 3.0.A delineates the ~ action to .be taken for-circumstances not directly provided for in the systems LCOs and Hhose occurrence would violate the intent of the specification.~ Specification 3.0.B. delineates what additional conditions must be satisfied to permit operation to continue, consistent Hith the specifications for power sources, when a normal or emergency power . source is not operable. It allows operation to be governed by the ' time limits of the specifications associated with the LCOs for the normal- or emergency- power source, not . the individual-specifications for each system, subsystem, train, component or. device that is determined to be-inoperable solely because of' the O 3.0 !: =.
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inoperability of its normal or emergency power source. In addition, it specifically prohibits operation Hhen one division iS inoperable because its normal or emergency power source is inoperable and a safety subsystem, train, component or device in another division is inoperable for another reason. W 0 m l 3.0-2 a -. .. j.g ; , .
3.1 PROTECTIVE IMSTRUMENTATIOt! Aeolicability: Applies to the operating status of plant instrumentation which performs a protective function. Obiective: To assure the operability of protective instrumentation. Seecifications: A. The following operating requirements for plant protective instrumentation are given in Table 3.1.1:
- 1. The reactor mode in which a specified function must be operable including allowable bypass conditions.
- 2. The minimum number of operable instrument channels per operable trip system.
- 3. The trip settings which initiate automatic protective action.
- 4. The action required when the limiting conditions for operation are not satisfied.
B. 1. Failure of four chambers assigned to any one APRM shall O make the APRM inoperable.
- 2. Failure of two chambers from one radial core location in any one APRM shall make that APRM inoperable.
C. 1. Any two (2) LPRM assemblies which are input to the APRM system and are separated in distance by less than three (3) times the control rod pitch may not contain a combination of more than three (3) inoperable detectors (i.e., APRM channel failed or bypassed, or LPRM detectors failed or bypassed) out of the four (4) detectors located in either the A and B, or the C and D levels.
- 2. A travelling In-Core Probe (TIP) chamber may be used as an APRM input to meet the criteria of 3.1.B and 3.1.C.1, provided the TIP is positioned in close proximity to one of the failed LPRM's. If the criteria of 3.1.B.2 or 3.1.C.1 cannot be met, power operation may continue at up to rated power level provided a control rod withdrawal block is operating or at power levels less than 61%'of rated power until the TIP can be connected, positioned and satisfactorily -
tested, as long as Specification 3.1.B.1 and Table 3.1.1 are satisfied. Bases: The plant protection system automatically initiates protective functions to prevent exceeding established limits. In addition, A k ' 3.1-1 l g
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other protec?.ive instrumentation is provided to initiate action which mitigates the consequences of accidents or terminates operator control. This specification provides the limiting conditions for operation necessary to preserve the effectiveness of these instrument systems. Table 3.1.1 defines, for each function, the minimum' number of operable instrument channels for an operable trip system for the various functions specified. There are usually two trip systems required or available for cach function. The specified limiting conditions for operation apply for the indicated modes of operation. When the specified limiting condition cannot be met, the specified actions required shall be undertaken promptly to modify plant operation to the condition indicated in a normal manner. Conditions under which the specified plant instrumentation may be out-of-service,are also defined in Table 3.1.1. Except as noted in Table 3.1.1. for the auto depressurication instrumentation and for channel test or calibration an inoperable trip system will be placed in the tripped condition. A tripped trip system is considered operating since by virtue of being tripped it is performing its required function. This permits the instrument channels, logic channels, and other portions in the plant protection instrumentation system to be maintained, tested and calibrated uhile at the same time affording the plant the same degree of protection. All sensors in the untripped trip system must be operable, except as follows: a- ~.
- 1. The high temperature sensor system in the main steam line tunnel has eight sensors in each protection logic channel. This multiplicity of sensors serving a duplicate function permits this system to operate one year Hithout
_ calibration. Thus, if one of the temperature sensors causes a trip in one of the two trip systems, there are several cross checks, that would verify .if this were a real one. If not, this sensor could be removed from service. However, a minimum of two of eight are required to be operable and only one of the two is required to accomplish a trip in a single trip system.
- 2. One APRM of the four in each trip system may be bypassed without tripping the trip system if core protection is maintained. Core protection is maintained by the' remaining three APRM's in each trip system as discussed in Section VII-4.2.4.2. of the FDSAR.
- 3. One IRM channel in each of the two trip systems may be bypassed without compromising the effectiveness of the l
system. There are a few possible sources of rapid reactivity - l input to the system in the low power low flow condition. Effects of increasing pressure at zero or low void content are minor, cold Hater from sources available during startup is not much colder than that already in the system, temperature coefficients are small, and control rod patterns 3.1-2 f
c.re constrained to b3 uniform by operating procedures brcked up by the rod worth minimizer. North of individual rods is very low .in- a uniform rod pattern. Thus, of all possible sources of reactivity input, uniform control rod ' withdrawal is the 'most. probable cause of significant . power rise. Bacause.the flux distribution associated with uniform rod i withdrawals does not involve high local peaks, and because several rods must be moved to change power by a significant percentage of rated, the rate of power rise is very slow. Generally.the heat flux is in near equilibrium with the fission rate. In an assumed uniform rod withdrawal approach i to the scram level, the rate of power rise is no more than five percent. of rated per minute, and three operable IRM instruments in each trip system would be more than adequate , to assure a scram before the power Could exceed the safety limit. In many cases, if properly located, a single operable IRM channel in each trip system would suffice.
- 4. When required for surveillance testing, a channel is made inoperable. In order to- be able to test its trip function to the final actuating device of its trip system, the trip system cannot already be tripped by some other means
; such as a mode switch, interlock, or manual trip, Therefore, there will be times during the test 'that the channel is inoperable but not tripped. For a two channel trip system, this means that full reliance is being placed on the channel 4
that is not being tested. The probability of the trip system failing to perform its . function' when required under this configuration can be made' commensurate with a like probability under its normal configuration by . limiting the operating time in the test mode. An acceptable test duration O to meet this criterion is computed to be one hour based on the following considerations: (a) the increased probability of an unsafe failure for a one-out-of-one trip system in comparison to a one-out--
; of-two trip system; i (b) the probability that the one channel being relied' upon is itself inoperable at the begining of the test; (c) the probability that an -event will occur that requires the trip system to function during the time-spent in the test mode;
.(d) an unsafe failure rate of 2.5E-6/hr-(Sec. 4.1, p.~ .
4.1.2) for the channel; and . (e) a test interval-(time between tests) of one month. Bypasses of inputs- to a trip system other than the IRM and APRM bypasses are provided for meeting operational requirements listed' - i in the notes in Table.3.1.1. Note s' allows the "high water level, i in scram discharge volume" scram trip to be bypassed in-the refuel , ' mode.' In ~ order to reset : = the o safety ? system 7 after ' a scram-condition, it'is necessary to' drain the scram discharge volume- to ' clear.this scram input. condition. (This condition usually follows j l l O .3.1-3
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F cny scram, no mattcr what th3 initial clust might have been.) In order to do this, this particular scram function can be bypassed only in the refuel position. Since all of the control rods are completely inserted following a scram, it is permissible to bypass this condition because a control rod block prevents Hithdrawal as long as the sHitch is in the bypass condition for this function. The manual scram associated Hith moving the mode suitch to shutdown is used merely to provide a mechanism whereby the reactor protection system scram logic channels and the reactor manual control system can be energized. The ability to reset a scram twenty (20) seconds after going into the shutdown mode provides the beneficial function of relieving scram pressure from the control rod drives Hhich Hill increase their expected lifetime. To permit plant operation to generate adequate steam and pressure to establish turbine seals and condenser vacuum at relatively low reactor power, the main condenser vacuum trip is bypassed until 600 psig. This bypass also applies to the main steam isolation valves for the same reason. The action required when the minimum instrument logic conditions are not met is chosen so as to bring plant operation promptly to such a condition that the particular protection instrument is not required; or the plant is placed in the protection or safe condition that the instrument initiates. This is accomplished in a normal manner Hithout subjecting the plant to abnormal operating conditions. The action and out-of-service requirements apply to all instrumentation within a particular function, e.g., if the requirements on any one of the tuelve scram functions cannot be l met then control rods shall be inserted. The trip level settings not specified in specification 2.3 have been included in this specificatien. The bases for these settings are discussed below. The high drywell pressure trip is set at 2 psig. This trip Hill scram the reactor, initiate containment spray in conjunction with l loH-low reactor water level, initiate core spray, initiate primary containment isolation . initiate automatic depressurization in conjunction with loH-low-low reactor water level and core booster pump pressure developed, initiate the standby gas treatment system and isolate the reactor building. The scram function shuts the core doHn during the loss-of-coolant accidents. A steam leak of about 15 gpm and a liquid leak of about 35 gpm from the primary system Hill cause dryHell pressure to reach the scram point; and, therefore, the scram provides protection for breaks greater than the above. High dryHell pressure provides a second means of initiating the core spray to mitigate the consequences of a loss-of-coolant accident. Its set point of 2 psig initiates the core spray in < time to provide adequate core cooling. The break-size coverage of high dryHell pressure Has discussed above. LoH-loH Hater level and high drywell pressure in addition to initiating core spray also causes isolation valve closure. These settings are adequate 3.1-4
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to causs isolstion to minimiz2 th3 offsita dosa within required
- limits.
It is permissible to make the drywell pressure instrument channels s O inoperable during performance of the integrated primary containment leakage rate test provided the reactor is in-the cold shutdown condition. The reason for this is that the Engineered Safety Features, which are effective in case of a LOCA under these [ conditions, will Still be effective because they will be activated by low-low reactor water level. The high water level in the scram discharge volume setting is based on the design that 37 gallons of water in the scram
! discharge volume will permit the 137 control rods to scram with a pressure in the volume less than or equal to 65 psig. To provide further margin, one gallon of water collecting in the volume will cause an alarm. A second high level alarm is set at two gallons.
Detailed analyses of _ transients have shown that sufficient protection is provided by other scrams below 45% power to permit j bypassing of the turbine trip and generator lead rejection scrams. i However, for operational convenience, 40% of rated power has been chosen as the setpoint below which these trips are bypassed. This setpoint is coincident with bypass valve capacity. I A low condenser vacuum scram trip of 23" Hg has been provided to protect the main condenser in the event' that vacuum is lost. A loss of condenser vacuum would cause the turbine stop valves to close, resulting in a turbine trip transient. The low condenser vacuum trip anticipates this transient and scrams the reactor. , The condenser is capable of receiving bypass steam until 7" Hg vacuum thereby mitigating the transient and providing a margin. Main steamline high radiation is an indication of excessive fuel failure. Scram, reactor' isolation and condensor vacuum pump isolation are initiated when high activity is detected in the main l- .i
; steam lines. These actions prevent further release of fission j products to the environment. Thir is accomplished by: setting the trip at 10 times normal rated power background. Although these actions are initiated at this- level, at lower activities the 3
monitoring system also provides for continuous ~ monitoring .of radioactivity in the primary steam lines as discussed in Section VII-6 of the FDSAR. Such capability provides the operator with a j prompt-indication of any release of fission products from the fuel. to the reactor coolant above normal rated power background. :The gross failure. of any single fuel rod could release a sufficient amount'of activity to approximately double the background activity. , l, at normal rate power. This would be indicative of the onset of , fuel fsilures'and would ' alert _ the ' operator to the 'need' for- -
-)
. appropriate actions,- as defined by - Section. 6 of- these-- 1
- specifications.
i The settings to isolate'the isolation condenser in the event of=a .i break in the steam or condensate lines are based on the predicted-s maximum- flows that these' systems > would .' experience' during operation,' thus permitting operation while affording protection in
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th3 event of a br= k. The settings corr:spond to e floH rats of less than three times the normal flow rate of 3.2E5 lb/hr. The setting of ten times the stack release limit for isolation of the air-ejector offgas line is to permit the operator to perform normal, immediate remedial action if the stack limit is exceeded. The time necessary for this action Hould be extremely short when considering the annual averaging which is allowed under 10 CFR 20.106 and, therefore, Hould . produce insignificant effects on doses to the public. Four radiation monitors are provided which initiate isolation of the reactor building cnd operation of the standby gas treatment system. Two monitors are located in the ventilation ducts, one is located in the area of the refueling pool and one is located in the reactor vessel head storage area. The trip logic is basically a 1 out of 4 system. Any upscale trip Hill cause the desired action. Trip settings of 17 mr/hr in the duct and 100 mr/hr on the refueling floor are based upon initiating standby gas treatment system so as not to exceed allowed dose rates of 10 CFR 20 at the nearest site boundary. The SRM upscale of 5.0E5 CPS initiates a rod block so that the chamber can be relocated to a lower flux area to maintain SRM capability as power is increased to the IRM rcnge. Full scale reading is 1.0E6 CPS. This rod block is bypassed in IRM Ranges 8 and higher since a level of 5.0E5 CPS is reached and the SRM chamber is at its fully HithdraHn position. _ The SRM doHnscale rod block of 100 CPS prevents the instrument chamber from being withdraHn too far from the core iuring the period that it is required to monitor the neutron flux. This doHnscale rod block is also bypassed in IRM Ranges 8 and higher. It is not required at this poHer level since good indication exists in the Intermediate Ranges and the SRM will be reading approximately 5.0E5 CPS when using IRM Range 8 and higher. High flow in the main steamline is set at 120% of rated ficH. At this setting the isolation valves close and in the event of a steamline break limit the loss of inventory so that fuel clad perforation does not occur. The 120% floH Hould correspond to the thermal power so this would either indicate a line break or too high a power. l Temperature sensors are provided in the steamline tunnel to provide for closure of the main steamline isolation valves should a break or leak occur in this area of the plant. The trip is set at 50 8F above ambient temperatu*e at rated power. This setting Hill cause isolation to occur for main steamline breaks which result in a flow of a feH pounds per minute or greater. Isolt. tion occurs soon enough to meet the criterion of no clad perforation. The low-low-loH Hater level trip point is set at 4'8" above the top of the active fuel and Hill prevent spurious operation of the automatic relief system. The trip point established Hill initiate the automatic depressurization system in time to provide adequate core cooling. 3.1-6
.~ , _ . _ _ . _ _ . _ . _. ._ .~ . . _ _ _ _
i j Specification 3.1.B.1 dIfines thn ninimum number of APRM chtnn31 J inputs required to permit accurate average core power monitoring. Specifications 3.1.B.2 and 3.1.C.1 further define the distribution +
- 1. of the operable chambers to provide monitoring of local power
! changes that might be caused by a single rod withdrawal. Any nearby, operable LPRM chamber can provide the rer" tired input for l: sverage core monitoring. A Travelling Incore Probe or Probes can i be used temporarily to provide APRM inputs (s) _ until LPRM replacement is possible. Since APRM rod block protection is not i required below 61% of rated power,(1) as discussed. in Sections
- 2.3, Limitina Sofety System Settinas, operation may continue 5elow
~
61% as long as Specification 3.1.B.1 and the requirements of Table 3.1.1 are met. In order to maintain reliability of core monitoring in that quadrant Hhere an APRM is inoperable, it is l permitted to remova the operable APRM from service for calibration l and/or test provided that the same core protection is maintained j by alternate means. - In the rare event that Travelling In-Core Probes (TIPS) are used
- to meet the requirements 3.1.B or 3.1.C the licensee may perform
{ an analysis of substitute LPRM inputs to the APRM system using ' spare (non-APRM input) LPRM detectors and change the APRM system as permitted by 10 CFR 50.59. Under assumed loss-of-coolant accident conditions and under certain loss of offsite power conditions Hith no assumed loss-of-coolant accident, it is inadvisable to allow the simultaneous starting of emergency core cooling and heavy load auxiliary systems in order to minimize the voltage drop across the emergency buses and to protect against a potential diesel generator overload. The diesel generator load sequence time delay relays O provide this protective function and are set accordingly. repetitive accuracy rating of the timer mechanism as Hell as parametric analyses to evaluate the maximum acceptable tolerances The for the diesel loading sequence timers Here Considered in the establishment of the appropriate load sequencing. Manual actuation can be accomplished by the opvator and is considered appropriate only when the automatic load-sequencing has been completed. This Hill prevent simultaneous starting of heavy load auxiliary systems and protect against the ' potential for diesel generator overload. , Also, the ~ Closed Cooling Water and Service' Water pump circuit breakers Hill trip Whenever a loss-of-coolant. accident: condition exists. This- is -justified by Amendment 42 of the Licensing-Application which determined that these pumps Here not required during this accident condition.
Reference:
~
'(1) NEDO-10189 "An' Analysis of Functional Common Mode ', -
Failures in-GE BWR Protection and Control. Instrumentation" L.'G. Frederick,Let,'al.,IJuly:1970. 3.1-7 <
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3.2 REACTIVITY CONTROL Apolicability: - Applies tc core reactivity and the operating status of the reactivity control systems for the reactor. Obiective: To assure reactivity control capability of the reactor. Scecification: A. Core Reactivity The core reactivity shall be limited such that the core could be made suberitical at any time during the operating cycle, with the strongest operable control rod fully withdrawn and all other operable rods fully inserted. B. Control Rod System
- 1. The control rod drive housing support shall be in place during power operation and when the reactor coolant system is l
pressurized above atmospheric pressure with fuel in the I reactor vessel, unless all control rods are fully inserted l and Specification 3.2.A is Let.
- 2. The Rod Mcrth Minimizer (RWM) shall be operable during each reactor startup until reactor power reaches 10% of rated power except as follows:
(a) Should the RMM become inoperable after the first twelve rods have been withdrawn, the startup may continue provided that a second licensed operator verifies that the licensed operator at the retetor console is following the rod program. (b) Should the RHM be inoperable before a startup is commenced or before the first twelve rods are withdrawn, l one startup during each calendar year may be performed l without the RHM provided that the second licensed operator verifies that the licensed operator at the reactor console is following the rod program and provided that a Station Engineer from Core Engineering l Group also verifies that the rod program is being followed. A startup without the RUM as described in this subsection shall be reported in a special report to the Nuclear Regulatory Commission within 30 days of the startup stating the reason for the failure of the RUM, - the action taken to repair it and the schedule for completion of the repairs. 3.2-1 S I l' 7 .
. ~ .__ __ _ . . ._ . _ _ .. _.. ~ . _ _ . - . __ _ . -_. _ _ . . _ - - - ___. _ . _ _ _ _ _ _
- (c) Control rod pattarns shan be established so thitt the maximum Horth of any in sequence CCntrol rod shan i
be less than 1.25% delta k, except: I
- 1. During low power physics tests, and i
! 2. During Hithdrawal of Control rods Hhich do not i bring the reactor core to a critical condition.
- 3. The average of the scram insertion times of all operable i
control rods shall be no greater than: l ,' Percent of Rod Lenath Inserted Seconds 5 0.375 20 0.900 50 2.00 90 5.00 ! The average of the scram insertion times for the three fastest control rods of a n groups of four con kol rods in a tHo by tNo array shan be no greater than: Percent of Rod Lencth Inserted Seconds I r 5 0.398 20 0.954-50 2.120
; 90 5.300-I t
Any four red group may contain a control rod Hhich is valved out of service provided the .above requirements .and Specification 3.2.A are met. Time zero shall be taken as the
- de-energization of the pilot scram valve solenoids.
~4. Control rods Hhich cannot be moved With Control rod drive pressure shall be considered -inoperable. If a partiany or funy Withdrawn . control. rod drive cannot be moved With drive or scram pressure the reactor 'shall be brought to a shutdown condition within 48l hours unless.
investigation demonstrates that,the cause of the failure is not due to a failed control rod drive mechanism collet housing. Inoperable control rods shan' be valved out ofn service, . in..such positions. that Specification 3.2.A is met. In no case shan the number of rods. valved out of service be - greater' than six. during the power- operation. If this- ,
. specification is not met, the reactor shall be placed'in the shutdown condition.
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_ .5. Control rods ' stall not .be Hithdrawn.for approach to - criticality unless at least three source range channels have an observed count rate equal to or greater than 3 counts per. second. 1
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- 6. The control rod density sh211 be greittr thrn 3.5 percent during power operation.
C. Standby Liquid Control System
- 1. The standby liquid control system shall be operable at all times when the reactor is not shutdown by the control rods such that Specification 3.2.A is met and except as provided in Specification 3.2.C.3.
- 2. ihe standby liquid control solution shall be maintained within the volume-concentration requirement area in Figure 3.2-1 and at a temperature not less than the temperature presented in Figure 3.2-2 at all times when the standby liquid ccntrol system is required to be operable.
- 3. If one standby liquid control system pu= ping circuit becomes inoperable during the run mode and Specification 3.2.A is met the reactor may remain in operation for a period not to exceed 7 days, provided the pump in the other circuit is demonstrated daily to be operable.
D. Reactivity Anomalies The difference between an observed and predicted control rod inventory.shall not exceed the equivalent of one percent in reactivity. If this limit is exceeded and the discrepancy cannot be explained, the reactor shall be brought to the cold shutdown condition by normal orderly shutdown procedure. Operation shall not be permitted until the cause has been evaluated and appropriate corrective action has been completed. The NRC shall be notified within 24 hours of this situation in accordance with Specification 6.9.2. l Bases: Limiting conditions of operation on core reactivity and the reactivity control systems are required to assure that the excess reactivity of the reactor core is controlled at all times. The conditions specified herein' assure the capability to provide reactor shutdown from steady state and transient conditions and assure the capability of limiting reactivity insertion rates under accident conditions to values which do not jeopardize the reactor coolant system integrity or operability of' required safety features. The core reactivity limitation is required to assure the reactor can be shut down at any time when fuel is in the core. It is a r?striction that must be incorporated into the design of the core' fuel; it must be applied to the conditions resulting from core ialterations; and it must be applied in determining the required operability of the core reactivity control devices. The basic criterion is that the core at any point in its operation be capable of being made suberitical in the cold, xenon-free - l condition with the operable control rod of highest worth fully Hithdrawn and all other operable rods ' fully inserted. At most times in core life more than one control rod drive could fail . mechanically and this criterion would still be met. 3.2-3
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In ordIr- tn cssure thIt the basic criterion Hill be satisflid On additional design margin Has adopted; that the keff be less than 0.99 in the cold xenon-free condition With the rod of highest Horth fully withdraHn and an others fully inserted. Thus, the O design requirement is keff less than 0.99, whereas the minimum condition for operation is keff less than 1.0 with the operable rod of highest worth fully WithdraHn (1). This limit allows control rod testing at any time in' core life and assures that the plant can be shut down by control rods alone. The first cycle contains boron as a burnable neutron absorber in > the temporary control curtains which results in a core reactivity characteristic which increases Hith exposure, goes through a maximum and then decreases-(2). Thus it-is possible that a core could be more reactive later in the cycle than at the beginning. Satisfaction of the above criterion can be demonstrated conveniently only at the time of refueling since it requires the core to be cold and xenon-free. The demonstration is designed to - be done at these times and is such that if it is successful, the criterion is satisfied for the entire subsequent fuel cycle. The criterion win be satisfied by demonstrating Specification . 4.2.A at the beginning of each fuel cycle with the core in the l cold, xenon-free condition. This demonstration Hill include' consideration for the calculated reactivity characteristic during the following operating cycle and the uncertainty in this calculation. The control rod drive housing support restricts the outward-movement of a control rod to less than 3 inches in ,the extremely. remote event of a housing failure. (3) The amount of reactivity O which could be added by this sman amount of rod Hithdrawal, Hhich is lesc than a normal single HithdraHal increment, Hin not contribute to any damage to the reactor coolant system. The ; support is not required when no fuel is in the core since no.
. nuclear consequences could occur in the absence: of fuel. The support is not required if the reactor coolant system is at atmospheric pressure.since there Hould then be no driving force to rapidly eject a drive housing. The support is not required if all-control rods are fully inserted since the~ reactor, Nov1d remain subcritical even in the event of complete ejection of the strongest control rod (4).
The Rod North Minimizer (5) provides automatic supervision of. conformance to the specified control rod patterns. It serves as a _ backup. to -procedural control.of control rod North. In the event ; that the.RHM is out of service when required, a licensed operator, ; can manuany fulfin the control rod pattern conformance functions
~o f the RHM in Hhich case'the normal procedural controls are backed- l I
up by independent procedural controls to assure conformance'during control rod NithdraHl. . This alloNance to perform a startup-without .the RHM is limited to once each calendar year to assure a -
. high operability of the RHM NhiCh is. preferred 'over procedural controls.
Control rod sequences are characterized by' homogeneous, scattered. patterns of withdraHn rods'similar to that indicated in Figure. 7.-- 3.2-4D ; 1 l
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14 cf Ref;rence (12). The maximum rod strengths cncount r d in these patterns are presented in Figure 3-9 of Reference (12) and 3-12 of Reference (13). The maximum rod strength permitted by the patterns is less than 0.01 delta k which is below strengths uhich could threaten the reactor coolant system. Above 10% power even single operator errors cannot result in out-of-sequence control rod Horths which are sufficient to reach a peak fuel'enthalphy content of 280 cal /gm; thus, requiring operation of the RWM or verification by a second licensed operator that the operator at the reactor console is following the rod program below 10% rated power is conservative. A parametric analysis of the control rod drop accident was made in Reference (14), assuming the worst measured rod drop velocity and Technical Specification scram times, and the results indicate that a maximum in sequence rod Herth of 1.25% delta k is acceptable. The control rod system is designed to bring the reactor suberitical from a scram signal at a rate fast enough to prevent fuel damage. Figure III-1 of Amendment 69 to the FDSAR shows the control rod scram reactivity used in the transient analyses. Under these conditions, the thermal limits are never reached during the transient requiring control rod scram as presented in the FDSAR. .The limiting power transient is that resulting from a turbine stop valve closure with failure of the turbine bypass system. Analysis of this transient show that the negative reactivity rates resulting from a flux scram Hith the average response of an operable drives in conformance with the specified limits, provide the required protection. In the analytical treatment of the transients, 290 milliseconds are allowed between a neutron sensor reaching the scram point and the start of motion of the control rods. This is adequate and conservative uhen compared to the typical time delay of about 210 miniseconds estimated from scram test results. Approximately the first 90 milliseconds of each of these time intervals result from the sensor and circuit delays Hhen the pilot scram solenoid de-energizes. Approximately 120 miniseconds later, the control rod motion is estimated to actuany begin. However, 200 milliseconds is conservatively assumed for this time interval in the transient analyses and this is also included in the a nouable~ scram insertion times of Specification 3.2.B.3. The specified limits provide sufficient scram capability to accommodate failure to scram of any one operable rod. This failure is in addition to any inoperable rods that exist in the core, provided that those inoperable rods met the core reactivity Specification 3.2.A. Control rods (8) Hhich cannot be moved with control rod drive pressure are clearly indicative of an abnormal operating condition on the affected rods and are, therefore, considered to be inoperable. Inoperable rods are valved out of service to fix - their position in the core and assure predictable behavior. If the rod is funy inserted and then valved out of service, it is in a safe position of maximum contribution to shutdown reactivity. If it is valved out of service in a non-fully inserted position, that position is required to be consistent with the shutdown 3.2-5
- . I l'
I rcietivity limitation stst d in Sp2cification 3.2.A, which essures ; the core can be shutdoHn at all times with control rods. Although there are many possible patterns of inoperable control j O rods which Hould meet this specification, the operator Hill be , provided with only a limited number of predetermined pattr as which allow him to continue operation Hith inoperable rods. %a availability of allowable patterns to the operator assures that information for determining compliance Hith the specification is immediately available to him at the time a control rod becomes inoperable and does not require reliance on calculations at that time before compliance can be determined. The allowable inoperable rod patterns will be determined using information obtained in the startup test program supplemented by calculations. During initial startup, the reactivity condition of the as-built core Hill be determined. Also, sub-critical patterns of Hidely separated Withdrawn control rods Hill be observed in the control rod sequences being used. The observations, together with calculated strengths of the strongest control rods in these patterns Hill comprise .a set of alloHable separations of malfunctioning rods. During the fuel cycle, similar observations made during any cold shutdown can be used to update and/or increase the allowable patterns. ' The number of rods permitted to be valved out of service could be many more than the six allowed by the specification, particularly late in the operating cycle; however, the occurrence of more than six could be indicative of a generic problem and the reactor Hill be shutdown. Also if damage within the control rod drive mechanism and in particular, cracks in drive internal housings, O cannot be ruled out, then a generic problem affecting a number of drives cannot be ruled out. Circumferential cracks resulting from stress assisted intergranular corrosion have occured in the collet housing of drives at several BWRs. This type of cracking could occur in a number of drives and if the cracks propagated until severance of the collet housing occurred, scram could be prevented in the affected rods. Limiting the period of operation-Hith a potentially severed collet housing and requiring increased surveillance afte- detecting one stuck rod Hill assure that the reacter Hill not be operated Hith a large -number of rods with failed collet housings'. Placing the reactor in.the shutdown condition inserts the control rods and accomplishes the objective of the specifications on control rod operability. This operation is normally expected to be accomplished within eight hours. , l The source range monitor (SMR) system (9) performs no automatic safety function. It does provide the operator Hith a visual indication of neutron level Hhich is needed for. knowledgeable and-efficient reactor startup at loH neutron levels. LThe results 'of the reactivity accidents are functions of the initial neutron flux. The requirement of at; least 3 cps assures that. any- - transient begins at or above the initial value of 1.0E-8 of rated power used in the analyses of -transients from cold conditions. One operable-SRM channel Hould be adequate to monitor the approach to critical using homogeneous patterns of. scattered control rods.r J 3.2 6
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A minimum of thr:2 operab12 SRM's is rcquir:d es cn cdded conservatism. The standby liquid control system is designed to bring the reactor to a cold shutdown condition from the full power steady state operating condition at any time in core life independent of the control rod system capabilities (10). If the reactor is shutdown by the control red system and would be suberitical in its most reactive condition as required in Specification 3.2.A, there is no requirement for operability of this system. To bring the reactor from full power to cold shutdoun sufficient liquid control must be inserted to give a negative reactivity Horth equal to the combined effects of rated coolant voids, fuel Doppler, xenon, samarium and temperature change plus shutdown margin. This requires a boron concentration of 600 ppm in the reactor. An additional 25% boron, which results in an average boron concentration in the reactor of 750 ppm, is inserted to provide margin for mixing uncertainties in the reactor. The system is required to insert the solution in a time interval between 60-120 minutes to provide for good mixing in the reactor and to override the rate of reactivity insertion due to cooldokn of the reactor following the xenon peak. The liquid , control tank volume-concentration requirements of Figure 3.2.1 assure that the above requirements for liquid control insertion are met Hith one 30 gpm liquid control pu=p. The point (1937 gal.19.6%) (11) results in the required amount of solution being inserted into the reactor is not less than 60 minutes, and therefore, defines the maximum concentration-minimum volume requirements. The point (3737 gal, 10.3%)(11) results in the required amount of solution being injected into the reactor is not more than 120 minutes, and therefore, defines the minimum concentration requirement. The boundary joining these points results in the required amount of solution being inserted into the reactor in the interval 60-120 minutes. The maximum volume of 4213 gal is established by the tank capacity. The tank volume requirements include consideration for 137 gal of solution which is contained below the point where the pump takes suction from the tank and, therefore, cannot be inserted into the reactor. The range of solution volume during normal operation is expected to be 2387-2937 gal. The solution saturation temperature varies with the concentration of sodium pentaborate. The solution Hill be maintained at least 5"F above the saturation temperature to guard against precipitation. The 5"F margin is included in Figure 3.2.1. Temperature and liquid level alarms for the system are annunciated in the control room. The allowed time out of service for a standby liquid control-pumping circuit as well as other safety features is based on the following considerations. Systems are designed with redundancy to increase their availability and to provide backup if one of the - components is temporarily out of service. For instance, if a system has two components, one of which is needed, plant operation may continue while a component is out of service for a reasonable time during its repair. Of course, during the out-of-service-for-repair period, the availability of the total system is somewhat 3.2-7
e reduced. Since compon2nt's are generally discovzred in' a failtd
^
condition only at a regularly scheduled test, the component has
- already been out of service for an unknown time. On the average.
l the failed component has been out of service for one half the test interval (tau /2). In other Hords, setting a test interval, tau, , 4 implies that it is acceptable to risk having the component out of service for an average period of tau /2 after a failure. l There is some combination of redundance, failure rate, and test i interval that results in an acceptable low basic risk rate to j operate the plant. The average risk rate including allowance for , repair should be no higher than the. basic risk rate at normal ; Then if the average risk rate (including repair) is operation. equated to the basic risk rate (during normal operation), there is j a unique solution for a maximum out-of-service time, T. In other ' words, plant operation may. continue while a component of a redundant system is out of service for repair up'to a time of T, .; Hithout exceeding the acceptably low risk rate of normal ; operation. Each combination of n systems, r of which are needed f to perform the given function, has a solution for a repair time, + T, as a function of test interval, tau. . For the common case of two systems, one of which is needed. T -tau /3. That is, one out' of' tHo systems .(if only one_ is needed) may be out of service for repair.up to one third of the test interval. Following repair, both the standby liquid control pumping circuits are tested to demonstrate operability. ' The analysis results in a good guideline for maximum time cut of 3 service for redundant systems. The analysis assumes independence of the' systems and~ since every effort. is made to ' design i independence into redundant systems, a time out of service- near the calculated T is acceptable. The calculated repair time is an-1
" average" and the implication is that times longer than the average are allowable. HoHever, the conservative approach is to-limit all repair times to the calculated time T. In any event, repair should begin as soon as possible and proceed expeditiously,-
consistent Hith good craftsmanship. The availability of a system is a function of its test' interval. In general, the more frequent the tests, the higher .the i avr.ilability, because the? system is not allowed to remain in a l failed state for long periods of time. If one system .is out of service, the overall availability .of the functionjmay-be i ' maintained by testing the' remaining redundant -systems on. an appropriately shorter test interval. This method is particularly ; attractive on systems ~with a relatively high level of redundancy. ' With -an appropriately short test interval, the required function. availability can be maintained indefinitely. While one system undergoes. repair.
~ '
l Only one of the two standby liquid control system pumping circuits is required to accomplish the safety function of the system. If , one pumping circuit is, found to be inoperable. ,there is no" immediate threat to shutdown capability and reactor operation may. .- continue while repairs are being made. Therefore,.the time out of-service .for one of, the. pumping -circuits; is ~ based on- the ' consideration -given- above .forL one out of two system.- The test' , l --
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interval for pump operability is one/ month (Specification 4.2). An acceptable out of service time is then determined to be T =(tou/3) = (30 days /3) = 10 days During each fuel cycle excess operating reactivity varies as fuel depletes and as any burnable poison in supplementary control is burned. The magnitude of this excess reactivity is indicated by the integrated ucrth of control rods inserted into the core, referred to as the control rod inventory in the core. As fuel burnup progresses, anomalous behavior in the excess reactivity may be detected by comparison of actual rod inventory with expected inventory based on appropriately corrected past data. Experience at Oyster Creek and other operating BWR's indicates that the control rod inventory should be predictable to the equivalent of one percent in reactivity. Deviations beyond this magnitude would not be expected and Hould require thorough evaluation. One percent reactivity limit is considered safe since an insertion of this reactivity into the core would not lead to transients exceeding design conditions of the reactor system. The scram reactivity function which results from a typical end-of-cycle control rod density was presented in Reference 15 and used in the bounding transient evaluations for equilibrium 7 x 7 fuel and 8 x 8 fuel reload cores. The effects of various off-design control rod patterns on the scram reactivity function were examined in Reference 16. The results indicated that the control red density, not distribution, is the most significant parameter. Control rod densities as low as 3.5 percent Here examined with essentially the same results as for the scram reactivity function used in Reference 15. Lower control rod densities would require scram bank ucrth predictions in comparison to the 3.5 percent control red density predictions to support the centention that the effects of reduced control rod density maintain adequate margins to limits in the transient analyses.
References:
(1) FDSAR, Volume I, Section III - 5.3.1. (2) FDSAR, Volume II, Figure III 11. (3) FDSAR, Volume I, Section VI-3. (4) FDSAR, Volume I, Section III - 5.2.1. (5) FDSAR, Volume I, Section VII-9. (6) FDSAR, Volume I, Section III - 5.2.2. (7) Licensing Application Amendment 11, Question II-3. , l (8) FDSAR, Volume I, Section III-5 and Volume II, Appendix B. i - (9) FDSAR, Volume I, Sections VII.- 4.2.2 and VII - 4.3.1. (10) FDSAR, Volume I, Section VI-4. 3.2-9 4
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(ii) Licensing Application Amendment 55, S:ction 2. (12) Paone, C .J., Stirn, R .C., and Wooley,-J. A., Rod Drop Accident Analysis for Large Boiling Hater Reactors," NEDO-10527, March 1972 (13) Paone, C. J., Stirn, R. C., and Haun, J. M., " Rod Drop Accident Analysis for Large Boiling Hater Reactors, Addendum No. 2 Exposed Cores," NEDO-10527, Supplement 2, January 1973. (14) Oyster Creek Nuclear Generating Station, Docket l l No. 50-219, Amendment 74, " Rod Drop Accident Analysis," May 31, 1974. (15) Licensing Application Amendment 76, XN-74-45
* (Revision 2) and XN-74-41 (Revision 2), dated January 31, 1975.
(16) Oyster Creek Licensing Submittal, " Cycle 5 Reload and Loss-of-Coolant Accident Analysis Re-Evalation" dated April 30 1975, Response 16G. f a 3.2-10 l
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3.3 REACTOR COOLANT Applicability: Applies to the operating status of the reactor coolant system. Obiective: To assure the structure integrity of the reactor coolant system. Specification: A. Pressure Temeerature Relationshios (i) Hydrostatic Leakage Tests - the minimum reactor vessel temperature for hydrostatic leakage tests at a given pressure shall be in excess of that indicated by Curve A of Figure 3.3.1. (ii) Heatup and Cooldown Operations: Reactor non-critical-- the minimum reactor vessel temperature for heatup and cooldown operations at a given pressure when the reactor is not critical shall be in excess of that indicated by Curve B of Figure 3.3.1. (iii) Power operations -- The minimum reactor vessel temperature for power operations at a given pressure shall be in excess of that indicated by Curve C of Figure 3.3.1. (iv) Appropriate new pressure temperatur e limits must be approved as part of this Technical Specification when the reactor system has reached ten effective full power years of reactor operation. B. Reactor Vessel Closure Head Boltdown The reactor vessel closure head studs may be elongated by
.020" (1/3 design preload) with no restrictions on reactor vessel temperature as long as the reactor vessel is at atmospheric pressure. Full tensioning cf the studs is not permitted unless the temperature of the reactor vessel flange and closure head flange is in excess of 100"F.
C. Thermal Transients
- 1. The average rate of reactor coolant temperature change during normal heatup and cooldown shall not exceed 100 F in any one hour period.
- 2. The pump in an idle recirculation loop shall not be -
started unless the temperature of the coolant within the idle i recirculation loop is within 50"F of the reactor coolant l temperature. 1 3.3-1 I l' ?
D. R acter Coolant Syst+m Leakaca Reactor coolant leakage into the primary containment from unidentified sources shall.not exceed 5 gpm. In addition, the total leakage in the containment, identified and unidentified, shall not exceed 25 gpm. If these conditions cannot be met, the reactor will be placed in the cold shutdown condition. E. Reactor Coolant Quality
- 1. The reactor coolant quality shall not exceed the following limits during power operation with steaming rates to the turbine-condenser of. less than 100,000 pounds per hour.
conductivity 2.u mho/cm chloride ion 0.1 ppm
- 2. The reactor coolant quality shall not exceed the following limits during power operation with steaning rates to the turbine-condenser of at least 100,000 pounds per hour.
conductivity 10.u mho/cm chloride ion 1.0 ppm
- 3. If Specification 3.3.E.1 and 3.3.E.2 cannot be met, the reacter shall be placed in the cold shutdown condition.
F. Recirculation Loop Operability
- 1. The reactor shall not be operated with one or more recirculation loops out of service except as specified in Specification 3.3.F.2.
- 2. Reactor operation with one idle recirculation loep is permitted provided that the idle loop is not isolated from the reactor vessel.
- 3. If Specifications 3.3.F.1 and 3.3.F.2 are not met the reactor shall be placed in the cold shutdown condition within 24 hours.
G. Primary Coolant System Pressure Isolation Valves
- 1. During reactor power operating conditions, the integrity' of all pressure isolation valves listed in Table 3.3.1 shall be demonstrated. Valve leakage shall not exceed the amcunts indicated. ,
l
- 2. If 3.3.G.1 cannot be met, an. orderly shutdown shall be ~
initiated and the reactor shall be in the cold shutdown - condition within 24 hours. Bases: The reactor coolant system (1) is a primary barrier against the release of fission products to the environs.. In order to provide assurance that this barrier is maintained at a.high degree of 3.3-2 ". 'l 'l' .$
' ~
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=.mm /'! y - i. J
I intigrity, rcstrictions hav2 been pliced on the operating j conditions to which it can be subjected. The Oyster Creek reactor vessel was designed and manufactured in accordance Hith General Electric Specification 21A1105 and ASME Section I as discussed in Reference 13. The original operating limitations were based upon the requirement 8that the minimum temperature for pressurization be at least 60 F greater than the nil-ductility transition (NDT) temperature. The minimum temperature for pressuri=ation at any time in life had to account for the toughness properties in the most limiting regions of the reactor vessel, as well as the effects of fast neutron embrittlement. Figures 3.3.1 is derived from an evaluation of the fracture toughness properties performed for Oyster Creek (Reference 12) in an effort to establish new operating limits. The results of neutron flux dosimeter analyses in Reference 12 indicate that the total fast neutron fluence (greater than 1 Mev) expected for Dyster Creek at the end of ten effective full power years of operation is 1.22E18 nvt on the inside surface of the reactor vessel core region shell. A conservative fast neutron fluence of 75% of this value is assumed at the 1/4 T (one quarter of Hall thickness) location for the preparation of the pressure / temperature curves in Figure 3.3.1. Stud tensioning is considered significant from the standpoint of brittle fracture only when the preload exceed approximately 1/3 of the final design value. No vessel or closure stud minimum temperature requirements are considered necessary for preload valuas below 1/3 of the design preload with the vessel depressurized since preloads below 1/3 of the design preload result in vessel closure and average bolt stresses which are less than 20% of the yield strengths of the vessel and bolting materials. Extensive service experience with these materials has _ confirmed that the probability of brittle fracture is extremely remote at these low stress levels, irrespective of the metal temperature. . The reactor vessel head flange and the vessel flange in combination with tne double "0" ring type seal are designed to provide a leak tight seal when bolted together. When the vessel head is placed on the reacter vessel, only that portion of the head flange near the inside of the vessel rests on the vessel flange. As the head bolts are replaced and tensioned, the vessel head is flexed slightly to bring together the entire contact surfaces adjacent to the "0" rings of the head and vessel flange. Both the head and the head flange have an HDT temperature of 40 F, and they are not subject to any appreciable neutron radiation exposure. Therefore, the minimum vessel head and head flange temperature for bolting the head flange and vessel flange is established as 40"F + 60"F or 100'F. Detailed stress analyses (4) Here made on the reactor vessel for both steady state and transient conditions with respect to material fatigue. The results of these analyses are presented and compared to allowable stress limits in Reference (4). The 3.3-3 O E 7 I l'-
l
?
specific conditions cnalyzed includid 120 cycles of normal startup and shutdown with a heating and cooling rate of 100'T per hour applied continuously over -a temperature range of 100 8F to 546"F and for 10 cycles of emergency cooldown at a rate of 300'F per ' hour applied over the same range. Thermal stresses from this . analysis combined with the primary load stresses fan within ASE ! Code Section III allowable stress intensities. Although the l Oyster Creek Unit i reactor vessel was built in accordance _with Section I of the ASME Code, the design criteria included in the reactor vessel specifications were in essential agreement with the criteria subsequently incorporated into Section III of the ( Code.(6) The expected number of normal heatup and cooldown cycles to which the vessel will be subjected is 80 (7). Although no heatup or cooldown rates of 300'r per hour are expected over the life of the vessel and the vessel design did not . consider such events (6), stress analyses have been made which showed the anowable number of such events is 22,000 on the basis of ASE Section III alternating stress limits. During reactor operation, the temperature of the coolant in an idle recirculation loop is expected to remain at reactor coolant temperature unless it is valved out of service. Repiringthe l coolant temperature in an idle loop to be within 50 F of the reactor coolant temperature before the pump is started assures that the change in ecolant temperature at the: reactor vessel i nozzles and bottom head region are within the conditions analyzed ) , for the reactor vessel as discussed above. 6 Allowable leakage rates of coolant from the reactor coolant system i have been based on the predicted and experimentany observed behavior of cracks in pipes and on the ability to make up coolant system leakage in the event of loss of offsite -AC power. The
- normany expected background leakage due to equipment design and
? the detection capability for determining coolant system. leakage were also considered in establishing the limits. The behavior of cracks in piping systems has been experimentany and analyticany investigated as part of the USAEC~ sponsored ' Reactor Primary Ccolant System Rupture Study.(the Pipe Rupture Study). .Work (8) utilizing 'the data obtained in this study indicates that leakage from a crack can be detected before the crack grows to a dangerous or critical size by ' mechanicany or thermany induced cyclic loading, or stress corrosion cracking or. some other mechanism characterized by gradual crack growth. This evidence suggests that for leakage somewhat greater than the ' limit specified for unidentified leakage, the probability is small that. imperfections or cracks associated' with .such leakage. would ^ grow rapidly. However, the establishment of allowable unidentified- leakage - greater than that given in 3.3-D, on thef . basis of. the data. presently available would 'be' premature because of uncertainties .) associated with the data. For leakage of the order of .5. gpa as- -' specified in 3.3-D,- the experimental and analytical data suggest a reasonable margin of safety that such 1==haga magnitude would- not result from .a . crack : approaching the critical ~-size for rapid i propagation. Leakage of the. magnitude specified can be.; detected l reascnably 'in a matter of a' fen hours utilizing the available ,_) f3.3-4
'Wa.
; e-_ .m .sgg .~,m -
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leakage dettetion schemes, tnd if th2 origin cannot be determined in a reasonably short time the plant should be shut down to alloH further investigation and corrective action. The drynell floor drain sump and equipment drain tank provide the primary means of Icak detection (9,10). Identified leakage is that from valves and pumps in the reactor system and from the reactor vessel head flange gasket. Leakage through the seals of this equipment is piped to the drynell equipment drain tank. Leakage from other sources is classified as unidentified leakage and is collected in the dryHell floor drain sump. Leakage Hhich does not flash in a vapor Hill drain in the sump. The vapor Hill be condensed in the drywell ventilation system and routed to the sump. Condensate cannot leave the sump or the drain tank unless the respective pumps are running. Tha sump and tank are provided Hith tHo purps each and redundant alarms which Hill actuate on a predetermined pumpout rate (10). The alarms on the floor drain sump Hill be set at the normal, identified leakage plus 80% of the limit of 5 gpm for unidentified leakage. The alarms on the q uipment drain tank Hill be set to alarm at a floH Pate such that the total leakage (floor drain plus equipment drain) does not exceed the limit of 25 gpm for total leakage (10). Additional qualitative information (10) is available to the operator via the monitored drywell atmospheric condition. However, this information is not quantitative since fluctuation in atmospheric conditions are normally expected, and quantitative measurements are not possible. The temperature of the closed cooling Hater Hhich serves as coolant for the drywell ventilation system is monitored and also provides information Hhich can be related to reactor coolant system leakage (9). Additional protection is provided by the drywell high pessure scram which Hould be expected to be reached within 30 m'autes of a steam leak of about 12 gpm (10). During a loss of offsite AC power, the contiol red drive hydraulic pumps, Hhich are powered by the diesels, each can supply 110 pgm Hater makeup to the reactor vessel. A 25 gpm limit for total leakage, identified and unidentified, was established to be less than the 110 gpm makeup of a single rod drive hydraulic pump to avoid the use of the emergency core cooling system in the event of a loss of normal AC power. Materials in the primary system are primarily 304 stainless steel and zircaloy fuel cladding. The reactor Water chemistry limits are placed upon conductivity and chloride concentration since conductivity is measured continuously and gives an indication of abnormal conditions or the presence of unusual materials in the coolant, Hhile chloride limits are specified to prevent stress - corrosion cracking of stainless steel. Chloride stress corrosion tests on stressed 304 stainless steel specimens have been reported (11). According to the data, alloHable chloride concentrations could be set over an order of magnitude higher than the established limit of 1.0 ppm at the 3.3-5 O. l
- g ,
E 4= - m m .m__ mm%, , . _
oxygen concentrcion (0.2-0.3 ppa) thit Hill be pristnt during power operation. Oxygen is maintained at loH levcis by the turbine-condenser off-gas system. Zircaloy does not exhibit similar stress corrosion failures. Air saturated water (7 ppm oxygen) is pumped into the reactor as a result of operation of the control rod drive system. Therefore, , the oxygen level in the reactor water can be higher than 0.2-0.3 l ppm during startups or during periods of het standby when the reactor is not steaming at significant powers, and a more stringent limit of 0.1 ppm chloride has been established for these periods to insure that the combination of chloride and oxygen Hill always be Hell beloH stress corrosion failure limits (11). At reactor steaming rates of at least 100,000 pounds per hour boiling occurs in the reactor causing deaeration of the reactor water which maintains oxygen beloH operating levels.
~
In the case of BHR's where no additives are used in the primary coolant, and where neutral pH is maintained, conductivity provides a very good measure of the quality of the reactor Hater. When the conductivity is Hithin its proper normal range, pH, chloride, and , other impurities affecting conductivity and water quality must l also be within their normal ranges. Significant changes in conductivity provide the operator with a warning mechanism so that he can investigate and remedy the conditions causing the change. Heasurements of pH, chloride, and otner chemical parameters are made to determine the cause of the unusual conductivity and instigate proper corrective action, These can be donc before limiting conditions, Hith respect to variables affecting the boundaries of the reactor coolant, are exceeded. Several O techniques are available to correct off-standard reactor Hater quality conditions including removal of impurities from reactor water by the cleanup system, reducing input of impurities causing off-standard conditions by reducing power and placing the reactor in the cold shutdown condition. The major benefit of cold shutdown is to reduce the temperature dependent corrosion rates and thereby provide time for the cleanup system to re-establish proper water quality. Ensuring the operational status of the primary coolant system isolation valves listed in Table 3.3.1 is' intended to increase their reliability thereby reducing the potential of an intersystem lass of coolant accident. References (1) FDSAR, Volume I, Section IV-2. (2) (Deleted). (3) (Deleted). .. (4) Licensing Application Amendment 16,' Design Requirements Section. (5) -(Deleted).
- O V 3.3 .
ga. - f .y J.
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(6) FDSAR 0 Volume Ic Section IV-2.3.3 and Volume II, Appendix H. (7) FDSAR, Volume I, Table IV-2-1. (8) Licensing Application Amendment 34, Guestion 14. (9) Licensing Application Amendment 28, Item III-B-2. (10) Licensing Applico'. ion Amendment 32, Guesticn 15. (11) Licensing Application Amendment 11, Question VI-4. (12) Licensing Application Amendment 68, Supplement No. 6, Addendum No. 3. (13) Licensing Application Amendment 16, Page 1. O l l 3.3-7
- i .i . s
3.4 EMERGENCY CCOLING Appliccbility: Applies to the operating status of the emergency cooling systems. Obiective: To assure operability of the emergency cooling systems. Specification: A. Core Sprav System
- 1. The core spray system shall be operable at all times with irradiated fuel in the reactor vessel, except as otherwise specified in this section.
- 2. The absorption chamber water volume shall be at least 82,000 cubic feet in order for the core spray system to be considered operable.
- 3. If one core spray system loop or its core spray header delta P instrumentation becomes inoperable during the run mode, the reactor may remain in operation for a period not to exceed 7 days provided the remaining loop has no inoperable components and is demonstrated daily to be operable.
- 4. If one of the redundant active loop components in the O core spray system becomes inoperable during the run mode, the reactor may remain in operation for a period not to exceed 15 days provided the other similar component in the loop is demonstrated daily to be operable. If two of the redundant active 1 cop components become inoperable, the limits of Specification 3.4.A shall apply.
- 5. During the period when one diesel is inoperable, the core spray equipment connected to the operable diesel _ shall be operable.
- 6. If Specifications 3.4.A.3, 3.4.A.4, and 3.4.A.5 are not met, the reactor shall be placed in the cold shutdown condition. If the core spray system becomes inoperable, the reactor shall be placed in the cold shutdown condition and no work shall be performed on the reactor or its connected systems which could result in lowering the reactor water level to less than 4'8" above the top of the active fuel.
- 7. If necessary to accomplish maintenance or modifications to the core spray systems, their power supplies or water -
supplies, reduced system availability is permitted when the reactor is: (a) maintained in the cold shutdown condition or (b) in the refuel mode with the reactor coolant system i maintained at less than 212"F and vented, and (c) no work is performed on the reactor vessel and connected systems that V . 3.4-1 l c t 1-I
.I' .
could rssult in low: ring th3 re ctor H;tc.r 1; vel to 1:ss than 4'8" above the top of the active fuel. Reduced Core Spray System Availability is minimally defined as follows:
- a. At least one core spray pump, and system components necessary to deliver rated core spray to the reactor vessel, must remain operable to the extent that the pump and any necessary valves can be started or operated from the control room or from local control stations,
- b. The fire protecticn system is operable, and
- c. These systems are demonstrated to be operable on a weekly basis.
- 8. If necessary to accomplish maintenance or modifications to the core spray systems, their power supplies or water supplies, reduced system availability is permitted when the reactor is in the refuel mode Hith the reactor coolant system maintained at less than 212 F 0 or in the startup mode for the purposes of low power physics testing. Reduced core spray system availability is defined as follows:
- a. At least one core spray pump in each loop, and system components necessary to deliver rated core spray to the reactor vessel, must remain operable to the extent that the pump and any necessary valves in each loop can be started or operated from the control room or from local control stations.
- b. The fire protection system is operable and,
- c. Each core spray pump and all components in 3.4.A.Ba are demonstrated to be operable every 72 hours.
- 9. If Specifications 3.4. A.7 and 3.4. A.8 cannot be met, the requirements of Specification 3.4.A.6 will be met and work will be initiated to meet minimum operability requirements of 3.4.A.7 and 3.4.A.8.
- 10. The core spray system is not required to be operable.
when the following conditions are met:
- a. The reactor mode switch is locked in the " refuel" or "shtitdown" position,
- b. (1) There is an operable flow path capable of taking suction from the condensate storage tank and transfer.'ing Hater to the reactor vessel, and (2) The fire protection system is operable. <
- c. The reactor coolant system is maintained at less than 212'F and vented.
- d. At least one core spray pump, and system components necessary to deliver rated core spray flow to the 3.4-2 O
- . i e j
reactor vessel, must remain operable to the extent that . the pump and any necessary valves can be started or operated from the control room or from local control stations, and the torus is mechanically intact.
- e. (1) No work shall be performed on the reactor or its connected systems which could result in lowering the reactor water level to less than 4'8" above the top of -
the active fuel and the condensate storage tank level is greater than thirty (30) feet (360,000 gallens). At
~
least tuo redundant systems including core spray pumps and system components must remain operable as defined in
- d. above.
OR (2) The reactor vessel head, fuel pool gate, and separator-dryer pool gates are removed and the water level is above elevation 117 feet. NOTE: When filling the reactor cavity from the condensate storage tank and draining the reacter cavity to the condensate storage tank, the 30 foot limit does not apply provided there is sufficient amount of Hater to complete the flooding operation. B. Automatic Decressurization System
- 1. Five electromatic relief volves of the automatic depressurization system shall be operable when the reacter Hater temperature is greater then 212 F8 and pressurized above 110 psig, except as specified in 3.4.B.2 The automatic ..
pressure relief function of these valves (but not the automatic depressuri=ation function) may be inoperable or bypassed during the system hydrostatic pressure test required by ASME Ccde Section XI, IS-500 at or near the end of each
, ten year inspection interval.
- 2. If at any time there are only four operable electromatic relief valves, the reactor may remain in operation for a period not to exceed 3 days provided the motor operated isolation and air operated condensate makeup valves in both l isolation condensers are demonstrated daily to be operabic. "
- 3. If Specifications 3.4.B.1 and 3.4.B.2 are not met; reactor pressure shall be reduced to 110 psig or less, within 24 hours.
- 4. The time delay set point for initiation after coincidence of low-low-low reactor Hater level, high drywell pressure and core spray booster pump discharge pressure shall be set not to exceed two minutes. -
C. Containment Spray System and Emeroency Service Water System
- 1. The containment spray system and the emergency service Hater system shall ba cpcrable at all times with irradiated .
3.4-3 I l'
fuel in the rc:tetor v ssal, cxcipt ts Epecificd in Specifications 3.4.C.3, 3.4.C.4, 3.4.C.6 and 3.4.C.9.
- 2. The absorption chamber water volume shall not be less than 82,000 cubic feet in order for the containment spray and emergency service water system to be considered operable.
- 3. If one emergency service Hater system loop becomes inoperable, its associated containment spray system loop shall be considered inoperarle. If one containment spray system loop and/or its associt.ted emergency service water system loop becomes inoperable during the run mode, the reactor may remain in operation for a period not to exceed 7 days provided the remaining containment spray system loop and its associated emergency service water system loop each have no inoperable components and are demonstrated daily to be operable.
- 4. If a pump in the containment spray system or emergency service water system becomes inoperable, the reactor may remain in operation for a period not to exceed 15 days provided the other similar pump is demonstrated daily to be operable. A maximum of two pu=ps may be inoperable provided the tuo pumps are not in the same loop. If more than two ,
pumps become inoperable, the limits of Specification 3.4.C.3 I shall apply. , l S. During the period when one diesel is inoperable, the j containment spray loop and emergency service Hater system l 1 1 cop connected to the operabic diesel shall have no inoperable components. l
- 6. If primary containment integrity is not required (see Specification 3.5.A), the containment spray system may be made inoperable.
- 7. If Specifications 3.4.C.3, 3.4.C.4, 3.4.C.5 or 3.4.C.6 are not met, the reactor shall be placed in the cold shutdown condition. If the containment spray system or the emergency service Hoter system becomes inoperable, the reactor shall be placed in the cold shutdown condition and no uork shall be performed on the reactor or its connected systems which could result in lowering the reactor water level to less than 4'8" above the top of the active fuel.
- 8. .The containment spray system may be made inoperable during the integrated primary containment leakage rate test required by Specification 4.5, provided that the reactor is maintained in the cold shutdown condition and that no work is performed on the reactor or its connected systems which could result in lowering the reactor level to less than 4'8" above the top of the active fuel.
3.4-4 I 3 g __ l' j
l D. Centrol Red Drive Hydraulie Syst*m
- 1. The control rod drive (CRD) hydraulic system shall be operable when the reactor Hater temperature is above 212'T except as specified in 3.4.D.2 below. ,
i
- 2. If one CRD hydraulic pump becomes inoperable' when the reactor water temperature is above 212'F, the reactor may remain in operation for a period not to exceed 7 days provided the second CRD hydraulic pump is oper ating and is checked at least once every 8 hours. If this condition
> cannot be met, the reactor Hater temperature shall be reduced to 212'F. E. Core Spray and Containment Sprov Pump Compartments Dcors The core spray and containment spray pump compartments doors shall be closed at all times except during passage in order to consider the core spray system and the containment spray system operable. F. Fire Protection System
- 1. The fire protection system shall be operable at all times with fuel in the reactor vessel except as specified in Specification 3.4.F.2.
- 2. If the fire protection system becomes inoperable during the run mode, the reactor may remain in operation, provided both core spray system loops are operable with,no inoperable' c components. -
) Bases: This specification assures that adequate emergency core ecoling j capability is available when the core spray system is required.
; Based on the loss-of-coolant analysis for the Horst line break, a
_ccre spray of at least 3400 gpm is required within 36 seconds to
; assure effective core cooling.*(i) Thus, ~if one loop becomes inoperable, the operable leop is capable of providing cooling to the core and the reactor may remain in operation for a period of 7 days provided repairs can be completed within that time. The- 7 days is based upon the consideration discussed in the bases of Specification 3.2 and the pump operability tests of Specification 4.4. If repairs cannot be made, the reactor is depressurized and vented to prevent pressure buildup and no work is allowed to - be performed on the reactor which could result in loHering the Hater.
l level below the safety limit of 4'8".
- Core Spray System 2 is required to deliver 3640 gpm.
Each core spray _ loop 'contains redundant active components. i Therefore, with the loss of one of these components the system is still capable: of supplying rated flow and the system as a whole (both loops)~can tolerate an additional single failure of. one ~of
~its . active components and still perform the intended function and.
prevent clad melt. Therefore, if a redundant ; active _. component: fails, a longer :repairn period is _ justified based on the . consideration given in. the' bases of -Specification 3.2. The 3.4-5 m , , , _ _ m
consid; ration indic;t::s that for o on1 out of 4 requir: ment the time out of service would be (tau /1.71) = (30 days /1.71) = 17.5 days Specifications 3.4.A.5 ensures that if one diesel .is out of service for repair, the core spray system loop components on the l other diesel must be operable with no components out of service. This ensures that the loop can perform its intended function, even assuming one of its active components fails. If this condition is not net, the reactor is placed in a condition where core spray is no longer required. When the reactor is in the shutdown or refueling mode and the reactor coolant system is less than 212 0F and vented and no work is being performed that could result in lowering the water level to less than 4'8" above the core, the likelihood of a leak or rupture leading to uncovering of the core is very low. The only source of energy that must be removed is decay heat and one day after shutdown this heat generation rate is conservatively calculated to be not more than 0.6% of rated power. Sufficient core spray flow to cool the core can be supplied by ene core spray pump or one of the two fire protection system pumps under these conditions. When it is necessary to perform repairs on the core spray system components, power supplies or water sources, Specification 3.4.A.7 permits reduced cooling system capability to that which could provide sufficient core spray flow from two independent sources. Manual initiation of these systems is adequate since it can be easily accomplished within 15 minutes during which time the temperature rise in the reactor nill not reach 2200'F. In order to allow for certain primary system maintenance, which O will include control rod drive repair, LPRM removal / installation, reactor leak test, etc., (all performed according to approved procedures), Specification 3.4.A.8 requires the availability of an additional core spray ' pump in an independent loop, while this maintenance is being performed the likelihood of the core being uncovered is still considered to be very low, however, the requirement of a second core spray pump capable of full rated flow and the 72 hour operability demonstration of both core spray pumps is specified. Specification 3.4.A.10 allows the core spray system to be inoperable in the cold shutdown or refuel modes if the reactor cavity is flooded and the spent fuel pool gates are removed and a source of water supply to the reactor vessel is available. Hater would then be available to keep the core flooded. The relief valves of the automatic depressurization system enable the core spray system to provide protection against the small break in the event the feedwater system is not active. The containment spray system is provided to remove heat energy from the containment in the event of a loss-of-coolant accident. The flow from one pump in either loop is more than ample to provide the required heat removal capability (2). The emergency 3.4-6 O I l' ,i
s:rvica Hat:r syst:m provid:s cooling to tha contcinment spery heat exchangers and, therefore, is required to provide the I ultimate heat sink for the energy release in the event of a loss-of-coolant accident. The emergency service water pumping requirements are those which correspond to containment cooling heat exchanger performance implicit in the containment cooling description. Since the loss-of-coolant accident while in the cold shutdown condition would not require containment spray, the system may be deactivated to permit integrated leak rate testing of the primary containment while the reactor is in the cold shutdown condition. The control rod drive hydraulic system can provide high pressure coolant injection capability. For break sizes up to 0.002 square feet, a single control rod drive pump with flow of 110 gpm is adequate for maintaining the water level nearly five feet above the core, thus alleviating the necessity for auto-relief actuation (3). The core spray main pump compartments and containment spray pump compartments were provided with Hater tight- doors.(4) Specification 3.4.E ensures that the doors are in place to perform their intended function. Similarly, since a loss-of-coolant accident when primary containment integrity is not being maintained Hould not result in pressure build-up in the drywell or torus, the containment spray l system may be made inoperable under these conditions. This prevents personnel from coming in contact with torus water. References (1) Licensing Application, Amendment 65, Section B.VI.6. (2) Licensing Application, Amendment 32, Question 3. (3) Licensing Application Amendment 18, Question 1. (4) Licensing application, Amendment 18, Question 4. N 3.4-7 ,
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. "l ~lL
3.5 CO?ITAIfitiE?tT Apolicability: Applies to the operating status of the primary and secondary containment systems. Obiective: To assure the integrity of the primary and secondary containment system. Soecification: A. Primary Containment
- 1. At any time that the nuclear system is pressurized above atmospheric or Hork is being done which has the potential to drain the vessel and irradiated fuel is in the vessel, the suppression pool Hater volume and temperature shall be maintained Hithin the folloHing limits.
- a. Maximum Hater volume - 92,000 cubic feet
- b. Minimum water volume - 82,000 cubic feet
- c. Maximum Hater temperature (1) During normal poHer operation - 95"F (2) During testing which adds heat to the suppression pool, the Hater temperature shall not exceed 10"F above the normal power operation limit specified in (1) above. In connection Hith such testing, the pool temperature must be reduced to below the normal poHer operation limit specified in (1) above Hithin 24 hours.
(3) The reactor shall be scrammed from any operating condition if the pool temperature reaches 1100 F. Power operation shall not be resut.dd until the pool temperature is reduced beloH the normal poHer operation limit specified in (1) above. (4) During reactor isolation conditions, the reactor pressure vessel shall be depressurimed to i less than 180 psig at normal cooldoHn rates if the pool temperature reaches 120"F.
- 2. Maintenance and repair, including draining of the suppression pool, may be performed provided that the folloHing conditions are satisfied:
- a. The reactor mode sHitch is locked in the refuel or shutdoHn position.
3.5-1
- b. (1) Th:ra is cn operabis flow path espabic cf taking suction from the condensate storage tank and transferring Hater to the reactor vessel, and (2) The fire protection system is operable.
- c. The reactor coolant system is maintained at less than 212'F and vented.
- d. At least one core spray pump, and system components necessary to deliver rated core spray flow to the reactor vessel, must remain operable to the extent that the pump and any necessary valves can be started or operated from the control room or from local control stations, and the torus is mechanically intact.
- e. (1) No Hork shall be performed on the reactor or its connected systems which could result in lowering the reactor Hater level to less than 4'8" above the top of the active fuel and the condensate storage tank level is greater than thirty (30) feet (360,000 gallons). At least two redundant systems including core spray pumps and system components must remain operable as defined in
- d. above.
or (2) The reactor vessel head, fuel pool gate, and separator-dryer pool gates are removed and the Hater level is above elevation 117 feet. NOTE: When filling the reactor cavity from the condensate storage tank and draining the reactor cavity to the condensate storage tank, the 30 foot limit does not apply provided there is sufficient amount of water to complete the flooding operation.
- 3. Primary containment integrity shall be maintained at all times Hhen the reactor is critical or when the reactor water temperature is above 212"F and fuel is in the reactor vessel except while performing loH power physics tests at atmospheric pressure during or after refueling at power levels not to exceed 5 MHt.
- a. With one or more of the containment isolation valves shown in Table 3.5.2 inoperable:
(1). Maintain at least one isolation valve operable in each affected penetration that is open and within 4 hours (48 hours for the traversing in-core system) either; . a) _ Restore the inoperable valve (s) to operable status or i J . 3.5 , ~ g .g, 3b g o - _% g,aje __ _ _ __
b) Isolate ccch cff;cted penitrction by us2 of at least one deactivated automatic valve secured in the isolation position, or c) Isolate each effected penetration by use of at least one closed manual valve or blind flange. (2). An inoperable containment isolation valve of ine shutdown cooling system may be opened with a reactor water temperature equal to or less than 350"F in order to place the reactor in the cold shutdoun condition. The inoperable valve shall be returned to the operable status prior to placing the reactor in a condition where primary containment integrity is required.
- 4. Reactor Buildino to Suopression Chamber Vacuun Breaker System
- a. Except as specified in Specification 3.5.A.4.b below, two reactor building to suppression chamber vacuum breakers in each line shall be operable at all times when primacy containment integrity is required.
The set point of the differential pressure instrumentation which actuates the air-operated vacuum breakers shall not exceed 0.5 psid. The vacuum breakers shall move from closed to fully cpen when subjected to a force equivalent of not greater than 0.5 psid acting en the vacuum breaker disc.
- b. From the time that one of the reactor building to suppression chamber vacuum breakers is made or found to be inoperable. the vacuum becaker shall be locked closed and reactor operation is permissible only during the succeeding seven days unless such vacuum breaker is made operable sooner, provided that the procedure does not violate primary containment integrity.
- c. If the limits of Specification 3.5.A.4.a are l exceeded, reactor shutdoun shall be initiated and the reactor shall be in a cold shutdown condition within 24 hours.
. 5. Pressure Superession Chamber - Drvuell Vacuum Breakers
- a. When primary containment integrity is required, all l suppression chamber - drywell vacuum breakers shall be operable except during testing and as stated in Specification 3.5.A.5.b and c, below. Suppression chamber -
dryuell vacuum breakers shall be considered operable if:
- (1) The valve is demonstrated to open from closed to fully open Hith the applied force at all valve positions not exceeding that equivalent to 0.5 psi 3.5-3 W. -
; x-g +~s =;w
( ccting on the suppression chamber face of the valve disk. l (2) The valve disk Hill Close by gravity to Hithin 1 g not greater than 0.10 inch of -any point 'on the seal surface of the disk when released after being-opened by remote or manual means. (3) The position alarm system will annunciate-in the control room if the valve is open more than 0.10. inch at any point along the seal surface of the' disk. * ! b. Two of the fourteen suppression chamber - drywell vacuum breakers may be inoperable provided that they are secured in the closed position.
- c. One position alarm circuit for each operable vacuum breaker may be inoperable for up; to .15 days provided-that each operable suppression chamber - drywell vacuum breaker with one defective alarm circuit is physically verified to be closed immediately and daily during this period.
- 6. After completion of the startup test program .and t
demonstration 'of plant electrical output, the: . primary containment atmosphere -shall be reduced to less than 5.0% oxygen with nitrogen gas within 24 hours .after the reacter mcde selector switch is. placed in the run mode. . Primary containment deinerting may commence" 24 hours' prior to: a , scheduled shutdown. If Specifications 3.5.A.a,b,c(1) and' 3.'5.A.2 through
~
7. 3 5.A.5 cannot be met, reactor shutdown shall be' initiated and the reactor shall be in :the cold shutdown condition. 1 Hithin 24 hours.
- 8. Shock Suppressors (Snubbers)=
- a. During all modes of operation except cold shutdown and refuel, all safety related snubbers ~1isted in? Table 3.5.1 shall be operable except as noted 3.5.A.8.b,:c and.
d below.
- b. From and after the time' that ~ a snubber -is determined to be inoperable, continued reactor operation
-is' permissible only 'during -the succeeding. 72 hours
~.unless the snubber is sooner.made operable or , replaced.
- c. If the: requirements of 3.5.A.B.a Land 3.5.A.8.b cannot be met, an orderly shutdown shall -be initiated-and the reactor shall be in a cold shutdown condition '
within 36 hours.
-d. If La -snubber is determined to be' inoperable Hhile the reactor is in -the shutdown' or: refuel 1 mode,- thec a 3.5-4i
'M
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l snubber shall be mads operable or replaced prior to reactor startup.
- e. Snubbers may be added to safety related systems without prior License Amendment to Table 3.5.1 provided that a revision to Table 3.5.1 is included Hith the next License Amendment request.
- 9. Drvuell-Suporession Chamber Differential Pressure
- a. Differential pressure between the drywell and
~
suppression chamber shall be maintained Hithin the acceptable operating range shown on Figure 3.5.1 within 24 hours after the reactor mode selector switch is placed in the run mode. The differential pres pre may be reduced to less than the range shown on Figure 3.5.1 24 hours prior to a scheduled shutdown. The differential pressure may be decreased to less than the required value for a maximum of four hours during required operability testing of the suppression chamber l
- drywell vacuum breakers.
- b. If the d'fferential pressure of Specification 3.5.A.9.a cannot be ~ maintained, and the differential i pressure cannot be restored within the subsequent 6 hour period, an crderly shutdown shall be initiated and the reactor shall be in the shutdown condition Hithin the next 6 hours and the cold shutdown condition within the following 18 hours.
- c. Instrumentation to measure the drynell to -
suppression chamber differential pressure and the tcrus Hater level shall be operable at any time the differential pressure is required to be maintained by Specification 3.5.A.9.a. Operation may continue for up to thirty days Hith one instrument out of service. If
, both differential pressure or both Hater level instruments are not operable, or if one instrument is out of service for more than thirty days, and such indication cannot be restored in the next 6 hours, the l
reactor shall be in the shutdown condition within the next 6 hours and in the cold shutdown condition within the following 18 hours. B. Secondary Containment l 1. Secondary containment integrity shall be maintained at all times unless all of the following conditions are met.
- a. The reactor is suberitical and Specification 3.2.A is met. ,
- b. The reactor is in the cold shutdown condition.
- c. The reactor vessel head or the dryuell head are in place.
3.5-5
- ~ ,
I l'
l-
- d. No work' is being performed on th2 rsactor or its l* . connected systems in.the reactor building.
- e. No operations are being performed in, above,-or O around the spent fuel storage pool .that could cause release of radioactive materials.
Two separate and independent standby gas treatment
~
2.
-system circuits shall be operable when secondary containment integrity- is . required 'except as specified be Specification i 3.5.B.3. l
- 3. With one standby gas treatment ' system circuit inoperable
- a. During Power Operation:
-(1). Demonstrate the operability of. the 'other standby gas ' treatment system circuit within 7.
hours, and (2). Continue to demonstrate the operability of th! standby gas treatment system circuit .once per 24 hours until the- inoperable standby gas treatment circuit is returned to operable status. (3). Restore the inoperable standby. gas treatment circuit to operable status within 7 days' or be subcritical..With reactor coolant temperature less. than 212"F within the next 36 hours,
- b. During Refueling:
(1). Demonstrate.'the operability of the redundant standby gas treatment system Within 2 hours, and (2). Continure to demonstrate the oparability of. the redundant standby gas treatment ~ system once per 7' days until the inoperable system is returned to operable' status. (3). Restore theH inoperable standby gas treatment system to operable status within 30 days or cease all spent fuel handling,. core alterations 'or-operation that could reduce the shutdown margin. 4 .~ If Specifications 3.5.B.2L and 3.5.B.3 are not met,.
-reactor shutdown shall be initiated and the reactor.shall lbe' in -the cold: shutdown ~ condition' within -24. hours and thei condition of; Specification 3.5.B.11shall be met.
~
Bases: . Specifications l are placed~ on the' operating Jstatus .of- the. containment systems to assure their availability .to' control Ethe'. release of. any radioactive materials from irradiated fuel.in the event of an accident condition. The. primary containment system (1) provides_.a. barrier 'against uncontrolled release of fission-O 3.5-6
~
A 1 9 -9
- 1 g 3.,
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- m i _
products to the cnvirons in th3 event of a bre k in the rauctor coolant systems. Whenever the reactor coolant Hater temperature is above 212"F, failure of the reactor coolant system Hould cause rapid expulsion of the coolant from the reactor Hith an associated pressure rise in the primary containment. Primary containment is required, therefore, to contain the thermal energy of the expelled coolant and fission products which could be released from any fuel failures resulting from the accident. If the reactor coolant is not above 212"F there would be no pressure rise in the containment. In addition, the coolant cannot be expelled at a rate which could cause fuel failure to occur before the core spray system restores cooling to the core. Primary containment is not needed while performing low poHer physics tests since the rod Horth minimizer Hould limit the Horst _ case rod drop accident to 1.5% k. This amount of reactivity addition is insufficient to cause fuel damage. The absorption chamber water volume provides the heat sink for th? reactor coolant system energy releared following the loss-of-coolant accident. The core spray pumps and containment spray pumps are loc:ted in the corner rooms and due to their proximity to the torus, the ambient temperature in those rooms could rise during the design basis accident. Calculations (7) made, assuming an ' initial torus Hater temperature of 100"F and a minimum Hater volume of 82,000 cubic feet, indicate that the corner room ambient temperature would not exceed the core spray and containment spray pump motor cperating temperature limits, and, therefore, Hould not adversely affect the long term core cooling capability. The maximun water volume limit allows for an operating range Hithout significantly affecting accident analyses Hith respect to free air volume in the absorption chamber. For example, the containment capability (8) Hith a maximum Hater volume of 92,000 cubic feet is reduced by not more than 5.5% metal Hater reaction below the capability Hith 82,000 cubic feet. Experimental data includes that excessive steam condensing loads can be avoided if the peak temperature of the suppression pool is maintained below 160"F during any period cf relief valve operation , with sonic conditions at the discharge exit. Specifications have teen placed on the envelope of reactor operating conditions so that the reactor can be depressurized in a timely manner to avoid the regime of potentially high suppression chamber loadings. The technical specifications alloH for torus repair Hork or inspections that might require draining of the suppression pool when all irradiated fuel is removed or when the potential for draining the reactor vessel has been minimized. This specification also provides assurance that the irradiated fuel has an adequate cooling Hater supply for normal and emergency conditions Hith the reactor mode switch in shutdown or refuel - Whenever the suppression pool is drained for inspection or repair. The purpose of the vacuum relief valves is to equalize the pressure between the drywell and suppression- chamber and 3.5-7 I I' "
-suppression chamber and rea: tor building so that the containment external design pressure lim'.ts are not exceeded.
!- The vacuum relief sy; tem from the reactor building to the pressure supression chamber consists of two 100% vacuum relief breaker subsystems (2 parallel sets of 2 valves in series). Operation of. either subsystem will maintain the containment external pressure less than the external design pressure of the drywell by 2 psi; the external design pressure of the suppression chamber is 1 psi l (FDSAR Amendment 15, Section 11). The capacity of the fourteen suppression chamber to drywell vacuum relief valves is sized to limit' the external pressure of the drywell during post-accident drywell ecoling operations tc the design limit of 2 psi. They are sized on the basis of the Bodega Bay pressure suppression tests. (9)(10) In Amendment 15 of the Oyster Creek FDSAR, Section II, the area of 2920 sq. in.'is stated as the minimum area for flow of non-condensible gases from the suppression chamber to the drywell. To achieve this requirement... at least 12 of the 14 vacuum breaker valves (18" diameter) must be
, operable.
Each suppression chamber drywell vacuum breaker is fitted with a redundant pair of limit switches to provide fail safe signals to panel mounted indicators in the Reactor Building and alarms in the Control Room when the disks are open more than 0.1" at any' point along the seal surface of the disk. These switches are capable of transmitting the disk closed-to-door signal with 0.01" covement of the switch plunger. Continued reactor operation with failed-
; components is justified because of the redundancy of components and circuits and, most importantly, the accessibility of the valve.
s lever arm and position reference external to the valve. .The fail-safe feature of the alarm circuits assures operator attention if a line fault occurs. Conservative estimates of'the hydrogen produced, consistent with the core cooling system provided, show that the _ hydrogen air. mixture resulting from a loss-of-coolant accident is considerably-below the flammability limit and hence it cannot' burn,- and inerting' would not be needed. However, inerting of the primary containment was included in the proposed design and ' operation.
- The 5% oxygen limit is the oxygen' concentration limit stated by the American Gas Association for hydrogen-oxygen mixtures' below Hhich combustion will not occur.
To preclude the possibility 'of . starting up the reactor and operating a long period of time with a significant1 lesk in the reactor coolant -system, leak checks must be made when the system- - is at or near rated temperature and pressure. It has- been shown~ (9)(10) that~ an ' acceptable ' margin with respect to flammability exists without containment' inerting. Inerting the primary containment provides additional' margin to that already considered ~ acceptable. ' Therefore, permitting access to the drywell : for _ the - purpose of -leak checking would not reduce the margin of safety below that Considered adequate and is judged prudent' in ~ ~ terms -- of-' the added plant safety offered by .the -opportunity-. forLleak1 4 inspection.- The 24-hour time to provide inerting is; judged tol be O V 3.5-8 [
-4 , ,,
. w- -~
- g. je< 74 w@ y _ y up& .- +- .. . u. a n n. w _+_a i _[ J
e r:asonable time to perform the operation and establish the required oxygen limit. Snubbers are designed to prevent unrestrained pipe motion under dynamic loads as might occur during an earthquake or severe transient, while allowing normal thermal motion during startup and shutdown. The consequence of an inoperable snubber is an increase in the probability of structural damage to piping as a result of a seismic or other event initiating dynamic loads. It is, therefore, required that all snubbers required to protect the reactor coolant system or any other safety system or component be operable during reactor operation. All safety related hydraulic snubbers are visually inspected for overall integrity and operability. The inspection Hill include verification of proper orientation, adequate hydraulic fluid level , and proper attachment of snubber to piping and structures. l Examination of defective snubbers at reactor facilities and material tests performed at several laboratories (Reference 11) has shown that millable gum polyurethane deteriorates rapidly under the temperature and moisture conditions present in many snubber locations. Although molded polyurethane exhibits greater resistance to these conditions, it also may be unsuitable for application in the higher temperature environments. Data are not currently available to define precisely an upper temperature limit ' for the molded polyurethane. Lab tests and in-plant e::perience indicate that seal materials are available, primcrily ethylene propylene compounds, which should give satisfactory performance under the most severe conditions expected in reactor installations. Because snubber protection is required only during low probability events, a period of 72 hours is allowed for repairs or replacements. In case a shutdown is required, the allowance of 36 hours to reach a cold shutdown condition Hill permit an orderly shutdown consistent with standard operating procedures. Since plant startup should not commence Hith knowingly defective safety related equipment, Specification 3.5.A.8.d prohibits startup with inoperable snubbers. Secondary containment (5) is designed to minimize any ground level release of radioactive materials which might result from a serious accident. The reactor building provides secondary containment during reactor operation Hhen the dryuell is sealed and $n service and provides primary containment Hhen the reactor is shutdown and the dryuell is open, as during refueling. Because the secondary containment is an integral part of the overall containment system, it is required at all times that primary containment is required. Moreover, secondary containment is required during fuel handling operations and whenever work is being performed on the reactor or its connected systems in the reactor building since their - operation could result in inadvertent release of radioactive material. The standby gas treatment system (6) filters and exhausts the reactor building atmosphere to the stack during secondary 3.5-9 c . g # g f _.g -
- , . . ;., m m_ , , , . ,
containment isolation' conditions, with a minimum release of.
~
radioactive materials from the reactor building to the environs. l n Two separate filter trains are provided each having 100% ! capacity.(6) If one filter train becomes inoperable, there is no l immediate threat to secondary containment and reactor. operation may continue while repairs are being made. Since the test
-interval for this system is one month (Specification 4.5), the time out-of-service allowance of 7 days is based on considerations presented in the Bases in Specification 3.2 for a one-out-of-two system.
In' conjunction with the Mark I Containment Shcrt Term Program, a plant unique analysis was performed on- August 2, 1976, which demonstrated a factor of safety of at least two for the Heskest element in the suppression- chamber support system. The maintenance of a drywell-suppression chamber differential pressure within the range shown on Figure 3.5.1 Hith a suppression chamber Hater level corresponding to a downcomer submergence range of 3.0 to 5.3 feet Hill assure the intergrity of the suppression chamber when subjected to post-LOCA suppression pool hydrodynamic forces.
References:
(1) FDSAR, Volume I, Section V-1. (2) FDSAR, Volume I, Section V-1.4.1. (3) FDSAR, Volu=e I, Section V-1.7. (4) Licensing Application, Amendment 11, Guestion III-25. (5) FDSAR, Volume I, Section V-2. (6) FDSAR, Volume I, Section V-2.4. (7) Licensing Application, Amendment 42. (0) Licensing Application, Amendment 32, Guestion 3. (9) Robbins, C. H. , " Tests on a Full' Scale '1/48 Segment of the Humboldt Bay Pressure Suppressica Containment, "GEAP-3596, November 17, 1960 (10) Bodega Bay Preliminary Hazards ' Summary Report, Appendix 1, Docket 50-205, December 28, 1952. (11) Report H. R.~Erickson, Bergen-Paterson to.K.'R. Goller, NRC, October 7,1974.
Subject:
Hydraulic Shock Shay Arrestors.
~3.5-10' A yC h e,b o
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3.6 RADI0 ACTIVE EFFLUENTS Acolicability: Applies to the radioactive effluents of the facility. Obiective: To assure that radioactive material is not released to the environment in an uncontrolled manner and to assure that the radioactive concentrations of any material released is kept to a practical minimum and in any event, Hithin the limits of 10 CFR 20. Specificction: A. Plant Stack Effluents (1) The maximum release rate of gross activity, except iodines and particulates Hith half lives longer than eight days, shall be limited in accordance Hith the fo11CHing equation: Q = (0.21/E) Ci/sec. Where Q is the stack release rate (Ci/sec) cf gross activity and E is the average gamma energy per di'sintegration (MeV/ dis). (2) The maximum release rate of iodines and particulates
, with half lives longer than eight days shall not exceed 4 uCi/sec.
(3) Radiogases released from the stack sna11 be continuously monitored except for the short time during monitor filter changes. If this specification cannot be met, the reactor shall be placed in the isolated condition. B. Discharce Canal Effluents (1) The release of radioactive liquid efflutats shall be limited such that the concentration of radionuclides in the discharge canal at the site boundary shall not at any time exceed the concentrations given in Appendix B, Table II, Column 2, of 10 CFR 20 and notes 1 through 5 thereto. l (2) Radioactive liquid effluent being released into the discharge canal shall be continuously monitored, or, if the monitor is inoperative, tHo independent samples of any tank to be discharged shall be taken, one prior to discharge and - one near the completion of discharge, and two station l personnel shall independently check valving prior to discharge of radioactive liquid effluents. 3.6-1
': ~.
I l'
l C. Radioactive Liquid Sterace ; The maximum amount of radioactivity, excluding tritium, noble l g gases, and chose isotopes with half lives shorter than three I ( days, contained in the radnaste storage tanks outside the radwaste building shall not exceed 10.0 curies. . If this activity exceeds 5.0 curies, then the stored liquid Hill be recycled to tanks within the radwaste facility until the icvel is reduced below 5.0 curies. D. Reactor Coolant Radioactivity The concentration of the total iodine in the reactor coolant shall not exceed 8.0 uCi/gm. If this specification cannot be met, the reactor shall be placed in the cold shutdown condition. E. Liquid Radioactive Haste Control Equipment installed for the treatment of liquid wastes shall be used if release of an untreated batch would result in concentrations in excess of 20% of the limits given in Section 3.6.B.(1). F. Annual Gaseous Release Limits
- 1. The average release rate of noble gases from the site during any calendar year shall be limited by the following equations:
for bata air dose: ['~'} V (3.17 E04) x (3.6 E-08) x SUMi Qi Hi less than or equal to 20 for gamma air dose: Sumi Qi Hi less than or equal to 10 Rhere: SUMi denotes summation over all isotopes detected 3.17 E04 = conversion factor pCi - yr/Ci-sec 3.6 E-08 = X/Q at site boundary _ 569 M SE. Qi = Average release rate of isotope i, in Ci/yr I Hi = dose conversion factor for beta air dose, mrad - m(3)/ pCi-yr from Table 3.6.1 Mi = dose conversion factor for gamma air dose,
-- mead /Ci from Table 3.6.1
- 2. The average release' rates of radiciodines and
,_q radioactive materials in particulate form released in gaseous t 's. .
3.6-2
~
; -l ~ ,la~ =
~ c,
cffluents from the sita during any calendar ye2r sh311 be limited by the following equation: (3.17 E-02) SUMi (Rii (4.8 E-08 x Dis + 2.3 E-05 x Qiv) + (Rgi + Rui) (5.5 E-09 x Qis + 1.0E-07 x Qiv) less than or equal to 15 Where: SUMi denotes summation over all isotopes detected 3.17 E-02 = conversion factor,*uci-yr/Ci-sec Rii = dose factor for inhalation, mrem-m(3)/uCi-yr, Table 3.6.2 Rg1 = dose factor for ground plane exposure, m(2) -mrem-sec/uCi-yr, Table 3.6.2 Rvi = dose factor for vegetation consumption m(2) -mrem-sec/ UCi-yr. Table 3.6.2 4.8 E-08 = X/Q at 890m SE for stack releases (Ref. 13) 2.3 E-05 = X/O at 890m SE for vent releases (Ref. 13) 5.5 E-09 = D/G at 890m SE for stack releases (Ref. 16) 1.0 E-07 = D/O at 890m SE for vent releases (Ref. 16) Qis = average release rate of isotope i from the stack in Ci/yr Giv = average release rate of isotope i from the vent in Ci/yr Note: The Rui for tritium should be multiplied by X/O rather than by D/O as ic done for all other nuclides. Bases: Some radioactive material is released from the plant under controlled conditions as part of the normal operation of the facility. Other radioactive material not normally intended for release could be inadvertently released in the event of certain accident conditions within the facility. Therefore, limits have been placed on the above types of radioactive materials to assure not exceeding the limits of 10 CFR 20 for the former type and the i guideline limits of 10 CFR 100 for the latter type. Radioactive gases from the reactor pass through the steam lines to the turbine and then to the main condenser where they are - l extracted by the air ejector, passed through 30-minute holdup l piping and released via the plant stack. The limits 'of release and radioactive material from the plant stack have been calculated using meteorological data from an instrumented 400 ft. tower at the plant site. The analysis of this onsite meteorological data shows that the expected composition of radiogases after 30 minutes 3.6-3 O I , I l'
l holdup in th3 off-gts-system, a continuous release of 0.3 Ci/sec r would not result in a Hhole body radiation dose exceeding the 10 CFR 20 value of 0.5 rems per year. The Holland plume rise model with no correction factor Has used in the calculation of the g effect of momentum and buoyancy of a continuously emitted plume. Independent dose calculations for several locations offsite have been made by the AEC staff. The method utilized onsite . meteorological data developed by the licensee and utilized diffusion assumptions appropriate to the site. The method is described in Section 7-5.2.5 of "Meterology and Atomic Energy - 1968" equation 7.63 being used. The results of these calculations l were equivalent to those generated by the licensee provided the average gamma energy per disintegration for the assumed noble gas mixture Hith a '30 minute hold up is 0.7 MeV per disintegration. Based on these calculations, a maximum release rate limit of gross activity, except for iodines and particulates Hith half lives longer than eight days, in the. amount of 0.21' x(average energy) curies per second Hill not' result in effsite annual doses in excess of the limits specified in 10 CFR 20. The average energy. determination need _ consider only the average gamma energy per-disintegration since the controlling whole body dose is due to the cloud passage over the receptor and not cloud submersion in which the beta dose could be additive. + Annual average ground level air concentration Has-Calculated (2) i using the 400 ft. site Heather data. The maximum calculated offsite concentration at ground- level for a continuous release rate of 1 curie /second Has found to be about 1.0E-9 -uCi/cc. This i maximum occurs about 1-1/2 miles north of the plant stack. Adjustment of the 1 curie /second' release rate. to the stack" O emission of 0.3 Ci/see to limit the ground level concentration to MPCa of 1.0E-10 uCi/cc for Iodine 131 gives an_ alloHable release rate of approximately 0.003 Ci/sec. Further adjustment'of this i rate by a factor of 700 in consideration of the- milk production and consumption mode of exposure gives the alloHable stack release rate of;4 uCi/sec set forth in the specification. Continuous monitoring of radiogases provides the means for 4' obtaining information on stack -release 1(4) ;for demonstrating. compliance Hith_ the stack release rate limits. In the event ~ continuous monitoring is not available, the reactor- is- isolated from the turbine condenser and, therefore, is isolated from the plant stack. The isolation .Hould normally be expected. to be completed Hithin 8 hours. It -is recognized that a precise determination of_ environmental dose from a certain emission from the stack is only ~ possible by direct measurement. Such information Hill be provided by the-environmental monitoring program (Section 4.6) f conducted at and around the site. If the stack emission ever reaches a level such.
-that it is measurable in the_ environment, such'. measurements- Hill. ~
j provide a basis for adjusting the. proposed stack limit long before the effect in the' environment is of any concern for permissible dose. 'In. this regard, it is~ important to realize that not-averaging emission rate over a period of one_. calendar year' as l permitted by 10 'CFR' 20 represents 'a very~1erge safety margin 3 . 6-4' _ .
betHeQn conditions at any ong instant (any minute, hour or day) and the long term dose of interest. The radioactive liquid effluents from the Oyster Creek Station Hill be controlled on a batch basis with each batch being processed by such method or methods appropriate for the quality and quantity of materials determined to be present. Those batches in which the radioactivity concentrations are sufficiently lou to allon release to the discharge canal are diluted with condenser circulating water in order to achieve the allouable concentrations set forth in the specifications.(6) The radioactive liquids Hill be sampled and analyzed for radioactivity prior to release to the discharge canal, thus providing a means for obtaining information on effluents to be released so that appropriate release rates Hill be established. The radioactivity concentration limits for the liquid effluents set forth in Specification 3.6.B.(1) are based on the limits contained in 10 CFR 20, Appendix B, Table II, Column 2. By excluding averaging for any time period, a margin is maintained between releases made in conformance with this limit and the limit specified in 10 CFR 20.106. When discharging on the basis of the limit for a mixture of unidentified isotopes (1.0E-7 uCi/cc), an estimate of radionuclide concentrations in aquatic biota has been made that correlates the resultant activity levels in the biota Hith the water limits for each isotope given in 10 CFR 20, Appendix B, Table II, Column 2. Based on conditions of minimun boy flushing and Hith a circulating water flon rate of 450,000 gpm the predicted concentration adjacent to the outlet of the discharge canal has a value of 1.5E-12 uCi/cc per uC1/ day discharged.(7)(8) This represents the concentration in the discharge canal undiluted by dispersion in the bay and based on this value, the average uCi/ day release rate that Hill yield a discharge canal concentration not exceeding 1.0E-7 uCi/cc is approximately 6.7E4 uCi/ day or about 25 curies / year. Assuming such releases, which is equivalent to releasing. continuously at the limit given in this specification, estimates are presented for clams, crabs, and fin-fish in Reference 9. The estimated concentration is less in each case than that permitted in drinking Hater for that radioisotope. There are several factors Hhich tend to make the estimates higher than Hould be expected. First, the estimates of bay concentrations are based on dispersion experiments conducted during a period of minimal dilution. Average dilution should be greater. Second, the recirculation effects assumed are greater than those calculated by the mathematical model that was used to estimate the effects of recirculation. When discharging on the basis of the limits for identified isotopes, consideration must be given to the reconcentration factors cited in Reference 9. A major consideration is that Hith all batch releases being less than the limit given in 10 CFR 20, Appendix B, Table II, Column 2 for each radioisotope, all periods of time when batch releases are not being made Hill apply in offsetting the effect of reconcentration. Verification of the adequacy of these limits Hill be obtained by performance of the 3.6-5 1
- 1 p- T p ~~. _
- ~
_- g . .
environmental monitoring program (Section 4.6). If the releases
- ever reach a level such that the biota sampling shows an increase in the background levels, such measurements Hill provide a basis A for adjusting the isotcpic limits long before the effect in the environment is of any concern for permissible dose.
Retaining radioactive liquids on-site in order to permit systematic and complete processing is consistent Hith maintaining radioactive discharges to the environment as loH as practicable. Limiting the stored contents to 10.0 curies of activity- assures that even in the extremely unlikely event of simultaneous rupture of all cf the tanks, the total activity discharged to the Bay would not be greater than the maximum activity recommended as the limiting condition for operation for the annual total quantity released in effluents that is given in proposed Appendix.I to 10 CFR 50. This amount of activity Hould also be less than half- the activity discharged to the Bay in one year if the plant Here to discharge continuously with the effluent having a radioactive concentration equal to the 10 CFR 20 HPC_ for unidentified isotopes. The main path' Hay to can for activity deposited in the Bay is through the comsuption of aquatic biota since there are no drinking Hacer supplies taken from the Bay. The concentrations that could develop in the canal are reduced rapidly in the Bay (see FDSAR Figure II.4.2). The peak concentrations exist for a relatively short time in the Bay and this combined with the uptake time of the biota could result in only minor increases in the equilibrium levels of radioisotopes in the biota. Isotopes with half lives less than three days are not of concern since there is sufficient delay between production in the plant, discharge by O(j means of this postulated accident and human consumption to preclude their being biologically significant. Tritium and noble gases are excluded also because they are not biologically significant. The requirement to process the tank contents if the activity inventory exceeds 5.0 curies assures action is taken on a timely basis to avoid reaching or exceeding the limit. The primary coolant' radioactivity concentration limit of 8.0 uCi total iodine per gram of Hater was' calculated based on a steamline break accident which is isolated in 10.5 seconds. For this accident analysis, all the iodine in the mass of coolant released in this time period is assumed to be released to the atmosphere at the top of the turbine building (30 meters). .By limiting the thyroid dose at the site boundary to a maximum of 30 REM, the iodine concentration in the primary coolant is back-calculated assuming fumigation meteorology, Pasquill Type F at 1 m/sec. The iodine concentration in the primary coolant resulting .from this analysis is 8.4 uCi/gm. The required use of equipment installed for the treatment of liquid Haste is specified for the purpose of limiting the liquid effluent radioactivity levels to a practical minimum. THenty percent of the Technical Specification limit for release of unidentified isotopes is equivalent to the guide value for design objectives given in the proposed Appendix I of 10 CFR 50. O (-) 3.6-6
- ?
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The nobic grs ralu ses are controlled so that the beta air dosa is
. less than or equal to 20 mrad /yr and the gamma air dose is less than or equal to 10 mead /yr (in accordance with 10 CFR 50 Appendix I) at the site 'oundary c in the direction Hith the highest X/Q. A
~
X/Q of 3.6 E-08 at 569 m in the SE direction was chosen on the basis of the NRC Appendix I analysis. The X/O used is that for releases from the stack, since almost all noble gas releases are from that source. Equations B-1 and B-4 from Regulatory Guide 1.109, Rev. 1 (October 1977) Appendix B, are used to calculate ths gamma and beta air doses, respectively. The site specific dose factors, Ni, for gamma air dose were obtained from the NRC RABFIN code and are based on the finite plume dose calculational mode. The releases of radiciodines and rsdioactive materials in particulate form are controlled so that the thyroid dose to any real person is less than or equal to 15 mrem /yr, in accordance Hith the design objectives of 10 CFR 50 Appendix I. The X/G and D/G values used are for a-distance of 890 m in the SE direction which is the location of the highest potential thyroid dose based on the Oyster Creek Appendix I Analysis (Ref. 12). The pathways considered at this location are stored and fresh fruits and vegetables, inhalation and ground plane deposition. No milk pathway exists at this location. The meat pathway is insignificant and is not considered (Ref. 12). Equations from NUREG-0133 (Ref. 14) are used to calculate the dose factors, along with dose conversion factors from Regulatory Guide 1.109 (Ref. 15). Where no data Has provided in Regulatory Guide 1.109 for thyroid dose converion factors for certain nuclides, the total body dose conversion factors were used. All calculations are done for a child since this produces the highest dose. (Ref. 12).
References:
(1) FDSAR, Volume I, Section IX-3.3. (2) Licensing Application, Amendment 13, Meteorological Radiological Evaluation for the Oyster Creek Nuclear Power Station Site. (3) Deleted. (4) FDSAR, Volume I, Section VII-6.2.3. (5) Deleted.
~
(6) FDSAR, Volume I, Section IX-3.1.1. (7) FDSAR, Volume I, Section II-4.3 . (8) Licensing Application, Amendment 11, Question 1-4. (9) Licensing Application, Amendment 11, Guestion 1-5. 1 (10) Deleted. 3.6-7
- I l' r _ = _
(11) Licensing Application, Amendment 11, Duestion IV-8. (12) Evaluation of the Oyster Creek Huclear Station to demonstrate conformance to the Design Objectives of 10 CFR 50 Appendix I, May 197G, Table 3-10 page 2 of 2. (13) Meteorological Information and Diffusion Estimates to Conform Hith Appendix I Requirements: Dyster Creek, July 1976, Table 1.3-11B. (14) HUREG-0133, Preparation of Radiological Effluent Technical Specifications for Nuclear Power Plants, Craft of August, 1978, Pages 30-33 and 36-37. (15) Regulatory Guide 1.109, Calculation of Annual Doses to Man from Routine Releases of Reactor Effluents For the Purpose of Evaluating Compliance Hith 10 CFR Part 50, Appendix I, Tables E-6, E-9, E-13. (16) Ref. 13, Table 1.3-13B. O 9
-3.6-8
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3.7 AUXILIARY ELECTRICAL POWER Apolicability:_ Applies to the operating status of the auxiliary electrical power supply. Obiective: To assure the operability of the auxiliary electrical power supply. Specification: The . 7ctor shall not be made critical unless all of the A. following requirements are satisfied:
- 1. The following buses or panels energized.
- a. 4160 volt buses 1C and 1D in the turbine building switchgear room.
- b. 460 volt buses 1A2, 1B2, 1A21, 1B21, vital MCC 1A2 and 1B2 in the reactor building switchgear room; 1A3 and 1B3 at the intake structure; 1A21A, 1821A, 1A21B, and 1B21B and vital MCC 1AB2 on 23'6" elevation in the reactor building; 1A24 and 1B24 at the stack.
- c. 208/120 volt panels 3, 4, 4A, 4B, 4C and VACP-1 in the reactor building switchgear room.
- d. 120 volt protection panel 1 and 2 in the cable room,
- e. 125 volt DC distribution centers C and B, and panel D, Panel DC-F, isolation valve motor control center DC-1 and 125 Volt DC motor control center DC-2.
- f. 24 volt DC power panels A and B in the cable room.
- 2. One 230 KV line is fully operational and switch gear and both startup transformers are energized to carry power to the station 4160 volt AC buses and carry power to or away from the plant.
l An additional source of power consisting of one of the
- 3.
following is in service and capable of feeding the l l appropriate plant 4160 v bus or buses: A second 230 KV line fully operational. a.
- b. One 34.5 KV line fully operational.
- 4. The station batteries B and C are available for normal service and a battery charger is in service for each battery.
3.7-1 I l' "
^
l B. The reacter shall be placed'in thm cold shutdown position if the availability of power falls below that required by Specification A above, except that the reactor may remain in operation for a period not to exceed 7 days in any 30 day period if a startup transformer is out of service. None of the engineered safety feature equipment fed by the remaining transformer may be out of service. C. Standby Diesel Generators
- 1. The reactor shall not be made critical unless both diesel generators are operable and capable of feeding their designated 4160 volt buses.
- 2. If one diesel generator becomes inoperable during power operation, repairs shall be initiated immediately and the other diesel shall be operated at least one hour every 24 i hours at greater than 20% rated power until repairs are completed. The reactor may remain in operation for a period not to exceed 7 days in any 30-day period if a diesel generator is out of service. During the repair period none of the engineered safety features normally fed by the operational diesel generator may be out of service or the reactor shall be placad in the cold shutdown condition.
- 3. If both diesel generators become inoperable during power.
operation, the reactor shall be placed in the cold shutdown condition. g 4. For the diesel generators to be considered operable j there shall be a minimum of 14,500 gallons of diesel fuel in the standby diesel generator fuel tank. Bases: The general objective is to assure an sdequate supply of power with at least one active and one' standby source of power available for operation of equipment required for a safe plant shutdown, to i maintain the plant in a safe shutdown condition and to operate the 1 required engineered safety feature equipment following 'an accident. AC power for shutdown and operation of. engineered safety feature equipment can be provided by any of four active (two 230 KV and two 34.5 KV lines)~ and either of two standby (two= diesel generators) sources of' power. Normally all six- sources are available. However, to provide for maintenance and repair of equipment and still have redundancy :of power -sources the requirement of one active and one standby source of power was established. The plant's main generator is not given credit as" a-6 source since it is not available_during shutdown._ The plant 125V DC_ power is normally supplied by two - batteries, i each with two.
. associated full capacity chargers. One charger on each battery.is: -
in service at all times with the seCond Charger available in the event of chargsr failure. These chargers are' active sources and supply the normal 125V DC requirements .with -the batteries and standby sources. (1) 3.7-2 - l l' ix ,
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In applying the minimum requirement of one cctiva and one standby source of AC power, since both 230 KV lines are on the same set of towers, either one or both 230 KV lines are considered as a single active source. The probability analysis in Appendix "L" of the FDSAR Has based on one diesel and shows that even with only one diesel the probability of requiring engineered safety features at the same time as the second diesel fails is quite small. This analysis used information on peaking diesels when synchronimation was required which is not the case for Dyster Creek. Also the daily test of the second diesel when one is temporarily out of service tends to improve the reliability as does the fact that synchronimation is not required. As indicated in Amendment 18 to the Licensing Application, there are numerous sources of diesel fuel which can be obtained within 6 to 12 hours and the heating boiler fuel in a 75,000 gallon tank on the site could also be used. Since the requirements for operation of the required engineered safety features after an accident or for safe shutdown can be supplied by one diesel generator the specification requirement for 14,500 gallons of diesel fuel can operate one diesel at a load of 2640 KH for 3 days. As indicated in Amendment 32 of the-Licensing Application and including the Security Systems loads, the load requirement for the loss of offsite power would require 12,410 gallons for a three day supply. For the case of loss of offsite power plus loss-of-coolant plus bus failure 9790 gallons would be required for a three day supply. In the case of loss of offsite power plus loss-of-coolant with-both diesel generators starting the load requirements (all equipment operating) shown there would not be three days' supply. HcHever, not all of this load is required for three days and, after evaluation of the conditions, loads not required on the diesel Hill be cur:* ailed. It is reasonable to expect that within 8 hours conditiene can be evaluated and the following loads curtailed:
- 1. One Core Spray Pump
- 2. One Core Spray Booster Pump
- 3. One Control Rod Drive Pump
- 4. One Containment Spray Pump
- 5. One Emergency Service Water Pump With these- pieces of equipment taken off at 8 hours after the:
incident it would require a total consumption of 12,840 gallons for a three day supply. l
References:
(1) Letter, Ivan R. Finfrock, Jr. to tha Director of. Nuclear Reactor Regulations dated April 14, 1978. 3.7-3 I g -.0 ___. - l'-
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l 3.8 ISOLATION CONDENSER I Apolicability: -
~
Applies to operating status of the isolation condenser. l l Obiective: A. The two isolation condenser loops shall be operable during power operation and whenever the reactor coolant. temperature is greater than 212'F except as specified in C, below. B. The shell side of each condenser shall centain a minimum water volume of 22,730 gallons. If the minimum volume cannot be maintained or if a source of makeup water is not available to the condenser, the condenser shall be considered inoperable. C. If one isolation condenser becomes inoperable during the run mode the reactor may remain in operation for a period not to exceed 7 days provided the motor operated isolation and condensate makeup valves in the operable isolation condenser are demonstrated daily to be operable. 4 D. If Specification 3.8.A and -3.8.B are not met, or if an inoperable isolation condenser cannot be repaired within 7 days, the reacter shall be placed in the cold shutdown condition. , Bases: The purpose of the isolation condenser is to depressurize the reactor and to remove reactor decay heat in the. event that the turbine generator and main condenser is unavailable as a heat sink.(1) Since the shell side of the isolation condensers operate at atmospheric pressure, they can accomplish their purpose when. the reactor temperature is sufficiently above 212'F to provide for the heat transfer corresponding to reactor decay heat. The tube side of the isolation condensers form a closed loop with the reactor vessel and can operate without reducing the reactor coolant water inventory. Each condenser containirig a minimum total water volume of 22,730 gallons provides 11,060 gallons above the condensing tubes.- Based on scram from a reactor power level of 1950 MHt (the design basis power level for the isolation condensers) the condenser system can accommodate the reactor decay heat (corrected for U-239 and HP-L 239) for 1 hour and 40 minutes without need for makeup water. One condenser with a minimum water volume of '22,730 gallons can 1 accommodate the reactor decay heat for 45 minutes after scram from 1950 MHt before makeup water is required. In order to accommodate - a scram from 1950 MHt and cooldown, a total of 107,500 gallons. of makeup. water would be required either from the condensate storage tank or from the fire protection system. Since the rated ^ reactor , power is- 1930 MHt, the above calculations represent conservative ! estimates of the isolation condenser system capability. ! l
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( Th2 v;nt linis from etch of the isolation condens;r loops to th4 main steam lines downstream of the main steam lines isolation valves are provided Hith isolation valves Hhich close automatically on isolation condenser actuation or on signals which close the main steam isolation valves. Radiation monitors on the condenser shell side vents and the associated alarms in the control room are provided to alert the operatcr of a tube leak in the isolation condenser. High temperature sensors in the isolation condenser and pipe areas cause alarm in the control room to alert the operator of a piping leak in these areas. Either of the two isolation condensers can accomplish the purpose of the system. If one condenser is found to be inoperable, there is no immediate threat to the heat removal capability for the reactor and reactor operation may continue while repairs are being made. Therefore, the time out of service for one of the condensers is based on considerations for a one out of two system.(4) The test interval for operability of the valves required to place the isolation condenser in operation is once/ month (Specification 4.8). An acceptable out of service time, T, is then determined to be 10 days. However, if at the time the failure is discovered and the repair time is longer than 7 days the reactor will be placed in the cold shutdown condition. If the repair time is not more than 7 days the reactor may continue in operation, but as an added factor of conservatism, the motor operated isolation and condensate makeup valves on the operable isolation condenser are tested daily. Expiration of the 7 day period or inability to meet the other specificctions requires that the reactor be placed~in the cold shutdoHn Condition which is normally expected to take no more than 18 hours. The out of service allowance when the system is required is limited to the run mode in order to require system availability, including ; redundancy, at startup. l
References:
(1) FDSAR, Volume I, Section IV-3. (2) K. Shure and D. J. Dudziak, " Calculating Energy Release by Fission Products". U.S. AEC Report, HAPD-T-1309, March 1961. (3) K. Shure, " Fission Product Decay Heat", in U.S. AEC Report, HAPD-BT-24 December 1961. (4) Specification 3.2, Bases. 3.8-2 O - I l' - __ 4
3.9 REFUELING Acolienbility: Applies to fuel handling operations during refueling. Obiective: To assure that criticality does not occur during refueling. Specification: A. Fuel shall not be loaded into a reactor core cell unless the control rod in that core cell is fully inserted. B. During core alterations the reactor mode switch shall be , locked in the REFUEL position. C. The refueling interlocks shall be operable with the fuel grapple hoist loaded switch set at less than or equal to 485 lb. during the fuel handling operations with the head off the reactor vessel. If the frame-mounted auxiliary hoist, the trolley mounted auxiliary hoist or the service platform hoist is to be used for handling fuel with the head off the reactor vessel the load limit switch on the hoist to be used shall be l set at less than or equal to 400 lb. l D. During core alterations the source range monitor nearest the alteration shall be operable. E. Rer oval of one control rod or rod drive mechanism may be performed provided that all the following specifications are satisfied.
- 1. The reactor mode switch is locked in the refuel position.
- 2. At least two (2) source range monitor (SRM) channels shall be operable and inserted to the normal operation level.
One of the operable SRM channel detectors shall be located in the core quadrant where.the control rod is being removed and ~ one shall be located in an adjacent quadrant. F. Removal of any number of control rods or rod drive mechanisms , may be performed provided all. the following specifications i I are satisfied-I
- 1. The reactor mode switch is locked in the refuel position-and all refueling interlocks are. operable as required in Specification 3.9.C. The refueling interlocks associated '
With the control rods being Hithdrawn may be bypassed as required after the fuel assemblies have been removed from the core cell surrounding the control rods as specified in 4, below. 3.9-1
- I l'- S A
- 2. At least two (2) source range monitor (SRM) channels shall be operable and inserted to the normal operation level.
Cne of the operable SRM channel detectors shall be located in the core quadrant where a control rod is being removed and one shall be located in an adjacent quadrant.
- 3. All other control rods are fully inserted with the exception of one rod which may be partially withdrawn not more than two notches to perform refueling interlock surveillance.
- 4. The four fuel assemblies are removed from the core cell surrounding each control rod or rod drive mechanism to be removed.
- 5. The core is suberitical by at,least 0.25% delta k, plus equivalent reactivity for the effect of any B4C settling in inverted tubes present in the core, with the most reactive remaining control rod withdrawn.
- 6. An evaluation Hill be conducted for each refuel / reload to ensure that actual core criticality for the proposed order of defueling and refueling is bounded be previous analysis performed to support such defueling and refueling activities, otherwise a new analysis shall be performed.
The new analysis must show that sufficient conservatism exits for the proposed order of defueling and refueling before such operation shall be allowed to proceed. G. Eth any of the above requirements not meE, cease core alterations or control rod removal as appropriate, and initiate action to satisfy the above requirements. Bases: During refueling operations, the reactivity potential of the core is being altered. It is necessary to require certain interlocks and restrict certain refueling procedures such that there is assurance that inadvertent criticality does not occur. Addition of large amounts of reactivity to the core is prevented by operating procedures, which are in turn backed up by refueling interlocks (1) on rod withdrawal and movement of the refueling platform. When the mode switch is in the " Refuel" position, interlocks prevent the refueling platform from being moved over the core if a control rod is Hithdrawn and fuel is on a hoist. Likewise, if the refueling platform is over the core with fuel on a hoist, control rod motion is blocked by the interlocks. With the mode switch in the refuel position only one control rod can be withdrawn (1)(2). The one rod withdrawal interlock may be bypassed in order to allow - multiple control rod removal for repair,' modifications, or core unloading. The requirements for simultaneous removal of more than one control rod are more stringent than the requirements for removal of a single control rod, since in the latter case Specification 3.2.A assures that the core Hill remain suberitical. 3.9-2 e
- I l'
t Fuel handling is normally conducted with the fuel grapple hoist. The total lead en this hoist when the~ interlock is required ' consists of the Height of the fuel grapple and the fuel assembly. This total is approximately 773 lbs. in the extended . position in comparison to the lead limit of 485 lbs. Provisions-have also been made to allow fuel handling with either.- of the three auxiliary hoists and still maintain the refueling interlocks. The 400 lb. load trip setting .no these hoists is adequate to trip the interlock Hhen one of the more than 600 lb. fuel bundles is being handled.
. The source range monitors provide neutron flux monitoring capabilities when the reactor.is.in the. refueling and shutdown modes (3). Specification 3.9.D assures that the neutron flux is monitored as close as possible to the location where fuel or ,
controls are being moved. Specifications 3.9.E and F require.the operability of at least two source range monitors when control rods are to be removed.
References:
(1) FDSAR, volume I, Section VII-7.2.5. (2) FDSAR, Volume I, Section XIII-2.2. (3) FDSAR, Volume I, Sections VII-4.2.2 and VII-4.3.1. O e O :3.9 . A b_^ WS :E # ~ 3 ,
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3.10 CORE LIMITS Applicability: Applies to core conditions required to meet the Final Acceptance Criteria for Emergency Core Cooling Performance. Obiective: To assure conformance to the peak clad temperature limitations during a postulated loss-of-coolant accident as specified in 10 CFR 50.46 (January 4, 1974) and to assure confermance to the 17.2 KH/ft. (for 7 x 7 fuel) and 14.5 KW/ft. (for 8 x 8 fuel) cperating limits for local linear heat generation rate. Specification: A. Average Planar L:'G_R During power operation, the average linear heat generation rate (LHGR) of all the rods in any fuel assembly, as a function of averaga planar exposure, at any axial location l shall not exceed the product of the maximum average planar l LHGR (MAPLHGR) limit shown in Figures 3.10-1 (for 5-1 cop operation) and 3.10.2 (for 4-1 cop operation) and the axial MAPLHGR cultiplier in Figure 3.10.3. If at any time during power operation it is determined by nermal surveillance that the limiting value for APLHGR is being exceeded, action shall be initiated to restore operation to Hithin the prescribed limits. If the APLHGR is not returned to within the prescribed limits within two (2) hours, action shall be initiated to bring the reactor to the cold shutdown. condition within 36 hours. During this period surveillance and corresponding action shall continue until reacter operation is within the prescribed limits at which time power operation may be continued. B Local LHGR During power operation, the linear heat generation rate (LHGR) of any rod in any fuel assembly, at any axial location shall not exceed the maximum allowable LHGR as calculated by the following equation: LHGR less than or equal to LHGRd (1-(delta P/P) max (L/LT)) where: LHGRd = Limiting LHGR (delta P/P) = Maximum Power Spiking Penalty - LT = Total Core Length - 144 inches L = Axial position above bottom of core Fuel Type LHGRd Delta P/P IIIF 17.2 .033 3.10-1
- I l'
4 V 14.5 .033 j VB 14.5 .039 l /] If at any time during operation it is determined by normal ,Q surveillance that- the limiting value for LHGR is being ! exceeded, action shall be initiated to restore operation to j Hithin the prescribed limits. If the LHGR is not returned to
- within the prescribed limits within tuo (2) hours, action 1 shall-be initiated to bring the reactor to the cold shutdown i condition within 36 hours. During this period, surveillance and corresponding action shall continue until reactor operation is within the prescribed limits at which time power j operation may be continued.
- C. Assembiv Averaced Power Void Relationship 4
l (Applicable to Fuel Type IIIF for 4-loop Operation Only) i j' During power operation, the assembly average void fraction-and assembly power shall be such that' the following relationship is satisfied:
, ((I-VF)/(PRxFCP)) greater than or equal to B l Where: VF = Bundle average void fraction l
PR = Assembly radial power factor j FCP = Fractional core power-(relative to 1930 MHt) j B = Power-Void limit-l The limiting values of "B" for fuel type IIIF is .377.
~
I { D. Minimum Criticci Pouce Ratio (MCPR) i
, During- steady state power operation, MCPR shall be greater j than or equal to the following:
I ! ARPM Status MCPR Limit I-l 1. If any tuo (2) LPRM assemblies Hhich 1.64 j are input to the APRM system and are separated in distance by less than i three (3) times the control rod pitch ! contain a combination of (3) out of four (4) detectors located in either the A and B or C and D levels Hhich j are failed or bypassed (i.e. , APRM channel j cr LPRM' input bypassed or inoperable.) , 1 I } 2.-If any LPRM input to the APRM system ,1.58
; at the B, .C, or D level is failed or
{ . bypassed or any APRM channel is inoperable ~ j (or bypassed). _ j.
- 3.L All B, C, and D LPRM inputs to the - . 1.52 4
APRM system are operating and no APRM j channels are inoperable or bypassed. q
.V '3.10-2
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Nh;n APRM stStus ch:ng:s dua to instrument frilure (APRM or LPRM input failure), the MCPR requirement for the degraded condition shall be met Hithin a time interval of eight (8) hours, provided that the control rod block is placed in . operation during this interval. If at any time during power operation it is determined by .- normal surveillance that the limiting value for MCPR is being exceeded for reasons other than instrument failure, action shall be initiated to restore operation to Hithin the prescribed limits. If the steady state MCPR is not returned to Hithin the prescribed limits Hithin two (2) hours, action shall be initiated to bring the reactor to the cold shutdown condition within 36 hours. During this period surveillance and corresponding action shall continue until reactor operation is within the prescribed limits at Hhich time power operation may be continued. Bases: The specification for average planar LHGR assures that the peak cladding temperature following the postulated 8 design bssis loss-of-coolant accident Hill not exceed the 2200 F limit specified in 10 CFR 50.46 (January 4, 1974) considering the postulated effects of fuel pellet densification. The peak cladding temperature following a postulated loss-of-coolant accident is primarily a function of the average heat generation rate of all the rods of a fuel assembly at any axial location and is only dependent secondarily on the rod.to rod poner distribution Hithin an assembly. Since expected local variations in power distribution within a fuel assembly affect the calculated peak clad temperature by less than plus or minus 20"F relative to the peak temperature for a typical fuel design, the limit on the average linear heat generation rate is sufficient to assure that calculated temperatures are below the limits specified in 10 CFR 50.46 (January 4, 1974). The maximum average planar LHGR limits shown in Figure 3.10.1 for Type IIIF, V and VB fuel for five loop operaticn and in Figure 3.10.2 for Type V and VB fuel for four loop operation are the result of LCCA analyses performed by Exxon Nuclear Company utilizing an evaluation model developed by Exxon Nuclear Company in co=pliance with Appendix K to 10 CFR 50 (2). Operation is permitted with the four-loop limits of Figure 3.10.2 provided the fifth loop has its discharge valve closed and its bypass and suction valves open. In addition, the maximum average planar LHGR limits shown in Figures 3.10.1 and 3.10.2 for Type V and VB fuel Here analyzed' with 100% of the spray cooling coefficients specified in Appendix K to 10 CFR Part 50 for 7x7 fuel . These spray heat transfer coefficients Here justified in the ENC Spray Cooling Heat Transfer Test Program (3).
~
The maximum average planar LHGR limits shown in Figure 3.10.2 for Type IIIF fuel for four loop cepration is the result of LOCA-analyses performed by Exxon Nuclear Company. utilizing blowdown results obtained from a General Electric Company evaluation model' in compliance with 10 CFR 50, Appendix K(1). Single failure 3.10-3 O I' 5 _ s . .
ll considerations were based on the revistd Oyster Creek Single Failure Analysis sub:nitted to the Staff on July 15, 1975. Thc effect of axial power profile peak location is evaluated for 2 O the worst break si=e by perfor'ing a series' of fuel heatup calculations. A set of multipliers is devised to reduce the allowable bottom skeHed axial power peaks relatiVB to Center or above center peaked profiles. The major factors which lead to the lower MAPLHGR limits with bottom skewed axial power profiles are the change in canister quench time at the axial peak location and a deterioration in heat transfer during the extended downward flow period during blowdown. The MAPLHCR multiplier in Figure 3.10.3 shall only be applied to MAPLHGR determined by the evaluation model described in Reference 2. The possible effects of fuel pellet densification are : 1) creep collapse of the cladding due to axial gap formation; 2) increase in the LHGR because of pellet column shortening; 3) power spikes . due to axial gap formation; and 4) changes in stored energy due to increased radial gap si=e. Calculations show that clad collapse is conservatively predicted not to occur during the exposure lifetime of the fuel. Therefore, clad collapse is not considered in the analyses. Since axial thermal expansion of the-fuel pellets is greater than axial shrinkage due to densification, the analyses of peak clad temperature do not consider' any, change in LHGR due to pellet column shortening. Although the formation of~ axial gaps might produce a local power spike at one-location on any one rod in al fuel assembly, the increase in local power density would be on the O order cf only 2% at the axial midplane. Since small local variations in power distribution have a sma11'effect on peak clad temperatures, power spikes were not considered in the analysis of
, loss-of-coolant accidents.
^ Changes in gap size affect the peak clad temperatures by their effect on pellet clad thermal conductance and fuel Lpellet stored energy. Treatment of this effect combined with the effects of' pellet' cracking, relocation and ' subsequent- gap closure are - discussed in XN-174. Pellet-clad ~ thermal conductance-for Type-IIIF, V and VB fuel was calculated using the~GAPEX model.(XN-174).- The specification for local LHGR' assures that_the linear heat generation rate in any rod is less than the limiting linear- heat generation even if fuel pellet densification is postulated. -The. power spike penalty for Type IIIF, V -and' VB _ fuel is based ;cn~ analyses presented in -Facility Change Request No. 5, Facility - Change Request No. 6 cnd Amendment 76, respectively. _The analysis assumes'a linearly: increasing variation in axial gaps between core? bottom and top, and assures with 95% confidence that:no morei than' one fuel rod exceeds the design linear heat. generation rate duettol ' power spiking. The General- ~ Electric non-jet pump BWR ECCS model (1) utMbs an L 'l empirical correlation :to determine : the duration ;of = nucleate l boiling heat transfer in the;early period following the postulated
- )
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pipe becak. This corralation for time to dryout is found to be proportional to the ratio of assembly water volume to power. Dryout time is a significant parameter in determining the extent of nucleate and transition boiling heat transfer, and consequently the peak cladding te=perature. - By maintaining reactor power and void fraction as specified in 3.10.C, dryout times at least as long as that used in the LOCA analysis will be assured. The limiting value of B in Specification 3.10.C was developed for core conditions of 100% power and 70% flow, the minimum flow that could be achieved without automatic plant trip (flow biased high neutron flux scram). Such a condition is never achieved during actual operation due to the neutron flux rod block and the inherent reactor powerflow relationship. The MAPLHGR results for fuel type IIIF shown in Figure 3.10.2 were evaluated for 102% power and 70% flow, thus the 2% conservatism for instrument uncertainty is retained in the limiting value of B. Additional conservatism is provided by the following assumptions used in determining the B limit.
- 1. All heat was assumed to be removed by the active channel flow.
No credit was taken for heat removal by leakage flow (10% of total flow).
- 2. Each fuel type was assumed to be operating at full thermal power rather than the reduced power resulting from the more limiting conditions imposed by Figure 3.10.2.
The loss-of-coolant accident (LCCA) analyses are performed using an initial core flow that is 70% of the rated value. The rationale for use of this value of flow is based on the possibility of achieving full power (100% rated power) at a reduced flow coidition. The magnitude of the reduced flow is limited by the flow relationship for overpower scram. The low flow condition for the LOCA analysis ensures a conservative analysis because this initial condition is associated with a higher initial quality in the core relative to higher flow-lower quality conditions at full power. The high quality-low flow condition for the steady-state core operation results in rapid voiding of the core during the blowdown period of the LOCA.The rapid degradation of the coolant conditions due to voiding results in a decrease in the time to boiling transition and thus degradation of heat transfer with consequent high peak cladding temperatures. Thus, analysis of the LOCA using 70% flow and 102% power provides a conservative basis for evaluation of the peak cladding temperature and the maximum average planar linear heat generation rate (MAPLHGR) for the reactor. The minimum critical power ratio (MCPR) calculated for the initial conditions of the LOCA represents the thermal margin of the hot assembly to the boiling transition point. An increase in core flow from 70% would result in additional thermal margin (higher MCPR valuc). The conservative ECCS analysis bounds the range of permitted reactor operating conditions so long as operating MCPR's are above the values computed for the initial conditions assumed for ECCS analysis. Current plant technical specifications 3.10-5 O - I l'
(3.10.D), b:std upon censitteration of other transients, limit the reactor operation on thermal margins substantially above the aesumed ECCS conditions. The assumed initial MCPR values for the ECCS analysis are 1.37 for 7x7 and 1.40 for 8x8 fuel. For transient operation up to the fuel cladding integrity safety
- limit, protection is provided against a MCPR of 1.34 for 8x8 fuel and 1.32 for 7x7 fuel. The actual steady-state operating power level provides margin to this limit by an amount corresponding to the maximum decrease in CPR resulting from singic operater error or equipment malfunction from a steady-state level. -
These resulting operating MCPR limits, combined with the transient analysis results, provide assurance that the fuel cladding integrity safety limit Hill not be violated during anticipated operating transients. The APRM response is used to predict when the rod block occurs in the anaylsis of the rod withdrawal error transient. The transient rod position at the rod block and correspending MCPR can be determined. The MCPR has been evaluated for different APRM responses which Hould result from changes in the APRM status as a consequence of bypassed APRM channel and/or failed or bypassed LPRM inputs. The results indicate that the steady state MCPR required to protect the minimum transient MCPR of 1.34 at the rod block ranges from 1.5 to 1.6 depending on the APRM system status (4). In order to provide for a limit which is considered to be bounding to future operating cycles, the variable limits have been conservatively adjusted upHard to range from 1.52 to 1.64. The time interval of eight (8) hours to adjust the steady state. MCPR to account for a degradation in the APRM status is justified on the basis of instituting a control rod block which precludes the possibility of experiencing a rod Hithdrawal error. transient since _ rod withdraHal is physically prevented. This time interval is adequate to allow the operator to either increase the MCPR to the appropriate value or to upgrade the status of the APRH system while in a condition Hhich prevents' the possibility of this transient occurring. References (1) Oyster Creek Nuclear Generating Station, Loss-of-Coolant-Accident Analysis Reevaluation and Technical Specification Change Request No. 42, Attachment I, dated December 23,1975.
- (2) XN-75-55-(A), XN-75-55, Supplement 1-(A), XN-75-55, Supplement 2-(A), Revision 2 " Exxon- ,
-. Nuclear Company HREM-Based NJP-BWR ECCS Evaluation O.-
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l l Model cnd Application to the Oyster Creek Plant," April 1977. (3) XN-75-36 (NP)-(A), XN-75-36 (NP) Supplement 1-(A),
" Spray Cooling Heat Transfers Phase 1 Test Results, ENC - 8x8 Fuel 60 and 63 Active Rods, Interim Report," October 1975.
(4) Oyster Creek Nuclear Generating Station Amendment 76 (Supplement No.4) Section 2.0, dated October 20, 1975. O l 3.10-7 O 1 c
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3.12 FIRE PROTCCTION Applicability: Applies to the operating status of Fire Detection / Suppression systems and associated instrumentation. Obiective: To assure that fire in safety related areas is detected and suppressed at an early stage so as to minimize fire damage to safety related equipment. . Soecificationi A. Fire Detection Instrumentation
- 1. As a minimum, the fire detection instrumentation for each fire detection area /=one shown in Table 3.12.1 shall be operable, except as otherwise specified in this section.
- 2. With the number of operable fire detection instruments less than required by Table 3.12.1:
- a. Hithin one hour, establish a fire Hatch patrol to inspect the area (s)/ ene(s) with the inoperable instrument (s) at least once per hour, and
- b. Restore the inoperabic instrument (s) to operable' status within 14 days or prepare and submit a special report to the Commission, in lieu of any other report required by Section 6.9, Hithin the next 30 days outlining the action taken, the cause of the inoperability and the plans / schedule for restoring the instrument (s) to operabla status.
l B. Fire Suppresion Water System
- 1. The Fire Suppression Water System shall be operable Hith:
l l a. Two high pressure pumps, each with a capacity of 2000 GPM, With their discharge aligned to the fire suppression header.
- b. Automatic initiation logic for each fire pump.
- c. An operable flow path capable of taking suction from the fire pond and transferring Hater through ~
distribution piping with sectionalizing control of valves to the yard hydrant curb valves and the first valve ahead of the water flow alarm device on each sprinkler, hose standpipe or spray system riser required to be operable per Specifications 3.12.C and 3.12.D. 3.12-1 I l'
4
- 2. With one pump inoperabla, r2 store th2 inoperab13 equipment to operable status within 7 days or prepare and submit a Special Report to the Commission, in licu of cny other report required by Section 6.9, within the next 30 days outlining the plans and procedures to be used to res, tore the inoperable equipment to operable status or to provide an j alternate pump. ,
- 3. With no Fire Suppression Water System operable.
- a. Within 24 hours establish a backup Fire Suppression Water System, or the reactor shall be placed in the cold shutdown condition .
- b. Submit a Special Report to the Commission, in lieu of any other report required by Section 6.9:
(1) By telephone within 24 hours, (2) Confirmed by telegraph, mailgram or facsimile transmission no later than the first working day folloHing the event, and (3) In writing Hithin 14 days folloHing the event, outlining the action taken, the cause of the inoperability and the plans and schedule for restoring the system to operable status. C. Sprov nnd/or Sprinkler Systems O 1. The spray and/or sprinkler systems listed in Table 3.12.2 shall be operable.
- 2. With one or more of the above required spray and/or sprinkler systems inoperable, within one hour establish a continuous
- fire Hatch with backup fire suppression equipment for those areas in Hhich redundant systems or components could be damaged; for other areas, establish an hourly -fire watch patrol.
3.- Restore the system to operable status within 14 days or prepare and submit a Special Report to the Commission, in lieu of any other report required by Section 6.9, within the next 30 days outlining the action taken,.the cause of inoperability and the plans / schedule for restoring the system to operable status. D. Fire Hose Stations
- 1. The Fire Hose Stations listed.in Table 3.12.3 shall be operable.. ...
- 2. With .a hose station listed in. Table 3.12.3 inoperable,.
Within one hour for areas where the inoperable hose . station is the primary means of fire suppression otherHise Hithin 24 hours, provide additional lengths of hose at another hose station' sufficient to reach the area of the inoperable hose O (~_I . 3.12-2
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1 l 4 ctition, unicss th2 rm son for inopercbility is e failura of the fire suppression Water system. In this event, additional hose lengths are not required and the requirements of Section 3.12.B.3 shall be fo11cHed.
- 3. Restore the affected hose station to cperable status O Hithin 14 days or prepare and submit a Special Report to the Commission, in lieu of any other report required by Section 6.9, Hithin the next 30 days outlining the action taken, the cause of inoperability, and the plans and schedule for restoring the station to operable status.
E. Fire 80erier Penetration Fire Seals
- 1. All penetration fire barriers protecting safety related fire areas shall be intact except for period of planned maintenance.
- 2. With one or more of the above required fire barrier penetrations non<-functional, Within one hour, either establish a continuous
- fire Hatch on at least one side of the affected penetration, or if the fire detectors on at least one side of the non-functional barrier are operable, establish an hourly fire watch patrol.
- 3. Restore the non-functional fire barrier penetration (s) to functional status Within 7 days or prepare and submit a Special Report to the Commission, in lieu of any other report required by Section 6.9, within the next 30 days outlining the action taken, the cause of nonfunction, the plans and schedule for restoring the fire barrier penetration to operable status.
F. Halen Svstems
- 1. The Halen Systems listed in Table 3.12.4 shall be operable with the storage tanks having at least 95% of full charge Height and 90% of full charge pressure.
- 2. With a Halon system inoperable Hithin one hour establish a fire Hatch patrol to inspect the affected area at least once per hour or a continuous
- fire Hatch with backup fire suppression equipment for those areas in which redundant systems or components could be damaged.
- 3. Restore the system to operable status within 14 days or l
prepare and submit a Special Report to the Commission, in lieu of any other report required by Section 6.9, Hithin the next 30 days outlining the action taken, the cause of I inoperability, and the plans / schedule for restoring the j system to operable status. , l 3.12-3 O I l'
' ~ ~ ~
G. $rbonDioxide(CO2) System ~
- 1. The 4160. Volt SHitchgear CO2 system shall-be operable
.Hith a minimum level greater than or equal to 1/2 full and a O minimum pressure of 275 psig in the associated storage tank.
- 2. With the CO2 system inoperable, Hithin one hour establisn a continuous
- fire watch with backup fire suppression equipment.
- 3. Restore the system to operabic status within 14 days or prepare and submit a Special Report to the Commission, in lieu of any other report required by Section 6.9, Hithin the
, next 30 days outlining the action taken, the cause of inoperability and the plans / schedule for restering the system to the operable status. H. Yard Fire Hydrants and Hydrant Hose Housr,1
- 1. The yard hydrants and associated hose houses listed in Table 3.12.5 shall be operable.
- 2. With one or more of the yard hydrants or associated
- hydrant hose houses shoHn in Table 3.12.5 inoperable, within one hour have sufficient additional lengths of 2 1/2 inch diameter hose located in an adjacent operable hydrant hose house to provide service to the unprotected area (s) if the inoperable fire hydrant er associated hydrant is.the primary means of fire suppression; otherwise, provide the additional hose within 24 hours.
- 3. Restore the hydrant or hose house to operable status Hithin 14 days or prepare and submit a special report to ' the Commission, in lieu of.any other report required by Section 6.9, Within the next 30 days outlining the action taken, the cause of the inoperability, and the plans and schedule for restoring the hydrant or hose house to operable status.
j
*In those areas which represent a radiation, airborn, or industrial safety hazard; an hourly fire watch patrol Hill be initiated in lieu of the continuous fire Hatch.
Bases: Fire Protection systems and instrumentation provide for early detection and rapid extinguishment of fires in safety -related areas thus minimizing fire damage. These specifications _ Hill i assure that.in the event of inoperable fire protection equipment, , corrective action Hill be initiated in order to maintair. fire protection capabilities during all modes of reacter 94 ration. The. pumps in the fire water suppression system have a capacity of l 2000 GPM each assuring an. adequate supply of Haterto -fire I suppression systems. Fire suppression Hater system operability as- 1' defined in 3.12.B.1 applies only as pertains to Specification 3.12 and is not applicable to other specifications. 3.12-4 l l L
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3.13 ACCIDENT MONITORING INSTRUMEllTATION O Ig Aeplicability: - Applies to the operating status of accident monitoring instrumentation. Obiective: To assure operability of accident monitoring instrumentation. Soecification: A. Relief Valve Position Indicators
- 1. The accident monitoring instrumentation channels shown in Table 3.13.1 shall be operable when the mode switch is in the Startup or Run positions.
- 2. With the number of operable accident monitoring instrumentation channels less than the Total Humber of Channels shown in Table 3.13.1, either restore the inoperable channels to operable status within 7 days, or place the reactor in the shutdown position Hithin 24 hours.
- 3. With the number of operable accid nt monitoring instrumentation channels less than the Minimum Channels Operable requirements of Table 3.13.1, either restore the inoperable channel (s) to the operable status Hithin 48 hours, O- or place the reactor in the cold shutdown condition Within 24 hours.
B. Safety Valve Position Indicators
- 1. During power operation, both primary
- and backup **
safety valve monitoring instruments are required to be operable except as provided in 3.13.B.2 and 3.13.B.3.
- 2. If either the primary
- or backup ** safety valve monitoring instruments on a valve become inoperable, the primary
- accident monitoring instrument on an adjacent valve must be operable, and its set point appropriately reduced.
- 3. If both the primary
- and backup ** accident monitoring instruments on a valve become inoperable and the primary
- accident monitoring instrument on an adjacent valve is operable, either restore the inoperable channel (s) to an operable status within .7 days, or place the reactor in the cold shutdoHD Condition Hithin 24 hours. .
- 4. If the requirements of Section 3.13.B.2 or 3.13.B.3 cannot be met Hithin 48 hours, place the reactor in the- cold )
shutdown condition Hithin 24 hours. I l i , b '
- 3.13-1
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C. In th2 cvent that cny of th;sa monitoring chann21s become inoperable, they shall be mada operzb13 prior to startup folloHing the next cold shutdown.
- Acoustic Monitor
** Thermocouple Bases: The purpose of the safety / relief valve accident monitoring instrumentation is to alert the operator to a stuck open safety / relief valve which could result in an inventory threatening event.
As the safety valves present distinctly different concerns than those related to relief valves, the technical specifications are separated as to the actions taken upon inoperability. Clearly, the actuation of a safety valve Hill be immediately detectable by observed increase in dryHell pressure. Further confirmation can ; be gained by observing reactor pressure and Hater level. Operator action in response to these symptoms would be taken regardless of the acoustic monitoring system status. Acoustic monitors act only to confirm the rescating of the safety volve. In actuality, the operator actions in response to the lifting of a safety valve Hill not change whether or not the safety valve resents. Therefore, T.he actions taken for inoperable acoustic monitors on safety valves are significantly less stringent than that taken for those monitors associated with relief valves. Should an acoustic monitor on a safety valve become inoperable, setpoints on adjacent monitCrs Hill be reduced to assure alarm actuation should the safety valve lift, since it is of no importance to the operator as to which valves lif t but only that one has liftad. Analyses, using very conservative blowdown forces and attenuation factors, show that reducing the clarm setpoint en adjacent monitors to less than 1.4g Hill assure alarm actuation should the adjacent safety valve lift. Minimum blowdown force considered was 30g with a maximum attenuation of 27 dB. In actuality, a safety valve lift Hould result in considerably larger blowdown force. The maximum attenuation of 27 dB Has determined based on actual testing of a similar monitoring system installed in a similar configuration. l l l . 3.13-2 o I l'
SECTION 4 SURVEILLANCE REQUIREMENTS 4.1 PROTECTIVE INSTRUMENTATION Applicabliltv: Applies to the surveillance of the instrumentation that performs a safety function. Obiective: To specify the minimum frequency and type of surveillance to be applied to the safety instrumentation.
~
Specification: Instrumentation shall be checked, tested, and calibrated as indicated in Tables 4.1.1, and 4.1.2 as per definitions given in Section 1. Bases: The minimum testing frequency is based on evaluation of unsafe failure rate data and reliability analysis. This, in turn, is based on operating experience at conventional and nuclear poHer plants. An " unsafe failure" is defined as one which negates channel operability and which, due to its nature, is revealed only when the channel is tested or attempts to respond to a bona fide signal. Failures such as blown fuses, faulted amplifiers, faulted cables, etc., Hhich result in " upscale" or "doHnsCale" indicatiCn l Hill be easily recogni=ed during operation of the reactor or by observation of the functioning instrumentation system and are not defined unsafe. Furthermore, such failures are, in many cases, revealed by alarm or annunciator action. The functions listed in Table 4.1.1. logically divide into three groups:
- a. On-off sensors that provide a scram function or some other equally important function.
- b. Analog devices coupled with a bi-stable trip that provides a scram function or some other vitally important function.
- c. Devices which only serve a useful function during some restricted mode of operation, such as startup or shutdoHn, or for Hhich the only practical test is one that can be performed only at shutdown.
Failure rate data for group (a) devices is available from many sources, including FARADA, AVCO, UKAEC, AIEE (Dickinson), Nuclear -; Engr / Gilbert Associates, Ralph M. Parsons, and General Electric Co. Although the data varies somewhat due to environment, the average unsafe failure rate is about 2.5E-6 failure /hr. The variance in failure rate data and the clean environment of atomic power plants indicate that sensor failure rates are smaller than 4.1-1
~ ~ .: a ~ .n , ., ,_ _ _ ,
th2 average for cil cpplications. To t2st cnd enlibrate a s;nsor requires that it be tripped, disconnected from its normal sensing line, and connected to a test line pressure source, then returned to its original state. This task requires an estimated 30 min'ates to 1 hour to complete in a thorough and workmanlike manner. Too frequent testing of the fifty-two sensors is a needless burden on plant operators. Consequently, field data will be collected (testing once/ month) and used with Figure 4.1.1 (1) to cajust the test interval. Figure 4.1.1 is a plot of the total number of failures r (all sensors) against M=nT(1-R) for a family of values of tau with a confidence level of 0.95, where n = 52, the total number of sensors T = Average time the sensors have been in service, hours R = 0.993, the necessary availability of a sensor. The value of R is the necessary individual sensor availability that results in a total system availability A. The IEEE Nuclear Safety Group Subcommittee on Reliability has tentatively proposed the goal of A = 0.9999 demonstrated system availability by operation data. For the one-out-of-tHo tHice logic,(2) R=1-(SQ RT((1-A)/2)) = 1-(SG RT((1-0.999)/2))=0.993 The in-service time T is average hours from initial startup, since the sensors are in service even during shutdown. To adjust the test frequency, first calculate the M factor, M = 0.36 x T, where T is average hours from initial startup. On Figure 4.1.1, locate the point of intersection of M and r, the number of unsafe failures since startup. The test interval associated Hith the line to the left of this point Hill assure an availability of 0.9999.
~
For example, suppose that after 18 months, 2 unsafe failures have occurred. M = 0.36 x 18 mo x 730 hours /mo. = 4700 To the left of the point (2,4700) is the line for tau =2 months, the test interval resulting in an availability of at least 0.9999. Had no unsafe failures occurred in the same time, tau could have been extended to 3 months. Testing once/mo is more frequent than is consistent Hith practicality, but can be tolerated for a limited time to establish predicted failure rates. When justified by actual field data, lengthening the test interval according to Figure 4.1.1 will . maintain an availability of at least 0.9999. The maximum test interval, regardless of field data, will be three months. Group (b) devices utilice an analog sensor followed by an amplifier and bi-stable trip circuit. The sensor and amplifier ' 4.1-2
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l c.ra stetive - components and a 'failura would genIrally result in an l upscale signal, a downscale signal, or no signal. These 4 - conditions are alarmed so a failure would not go undetected. The bi-stable portion does need to be tested in order to prove that it Hill assume its tripped state when required. Since the test and
- calibration equipment is built in, this test can be performed very l quickly and -more frequently without degrading reliability. With the instrument in the calibrate position, the calibration pot is varied up and down to verify input-output relationship and trip 4
points. The test frequency of once per Heek has developed 'I principally on the basis of past practice and good judgement and l nothing has developed to indicate that the frequency should change. ' Group (c) devices areactiveonlydurinhagivenportionofthe ;
- ~ operational cycle. For example, the IRM is inactive during full- !
i power operation and active during startup. Thus, the only test t that is significant is the one performed just prior to shutdown and startup. The condenser Low Vacuum trip can only be tested during shutdown, and although it is connected into the reactor protection system, it is not- required to protect the reactor. ! Testing at each refueling outage is adequate. The switches for l the high temperature main steam line tunnel are not accessible during normal operation because of their location above the main < steam lines. Therefore, after initial calibration and in-place operability checks, they Hill not be tested between refueling
, shutdowns. Considering the physical arrangement of the piping which would allow a steam leak at any of the four sensing locations to affect the other locations, it is considered that the function is not jeopardized by limiting calibration and' testing to refueling outages, t
- The icgic of the instrument safety systems in Table 4.1.1 is such
, that testing the instrument' channels also trips the trip system,
- verifying that -it is operable. .However, certain systems require, l coincident instrument channel trips to completely test their- trip systems. Therefore, Table 4.1.2 specifies the minimum trip system test frequency for these tripped systems. This a
- sures that all trip systems for protective instrumentation are adequately tested, from sensors through the trip system.
l Every element of electrical circuitry for the reactor protection ! system is to be verified operable prior to plant startupy by. functional ~ testing. . Parallel elements of circuits Hhich do not permit functional verification of freedom from shorts by routine channel trips are to be verified functional during refueling shutdown.
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References:
f , (1)- " Reliability'of Engineered Safety Features as a-l Function of Testing Frequency," I. H. Jacobs,.
' Nuclear Safety, Volume 9, No. 4, '
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. July-August, 1% 8. , j
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l t 1 (2) "ReacterProtectionSystems,AReliabilityAnakysis," I. H. Jacobs, APED-5179, Eng. A-18, June, 1966. O O 1 4.1-4
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4.2 REACTIVITY CO!ITROL 1 Applicability: Applies to the surveillance requirements for reactivity centrol. Obiective: i To verify the capability-for controlling reactivity. . Specification: A. Sufficient control rods shall be Hithdrawn following a refueling outage When core alterations Here performed to demonstrate with a margin of 0.25% delta k that the core can be made suberitical at any time in the subsequent fuel cycle with the strongest operable control rod fully withdrawn and all other operable rods fully inserted. B. The control rod drive. housing support system shall be inspected after reassembly. C. 1. After each major refueling outege and prior to resuming power operation, all operable control rods shall be scram time tested from the fully withdrawn position with reactor i pressure above 800 psig.
- 2. Following each reactor scram from rated pressure, the mean 90% insertion time shall. be determined for eight selected rods. If the mean 90% ' insertion time of the i selected control rod drives does not fall Hithin the range of 2.4 to 3.1 seconds or the measured scram time of any one driva for 90% insertion does not fall Hithin the range of 1.9-l to 3.6 seconds, an evaluation shall be made to provide reasonable assurance: that proper control . rod drive performance is' maintained.
- 3. FolloHing any outage not initiated by a reactor scram, eight rods shall be scram tested With reactor pressure above 800 psig provided these have not been measured in six months.
The same criteria of 4.2.C.2 shall apply. D. Each partially or fully. Withdrawn control rod shall'be j exercised at least once each week. This test shall :be performed - at least once per 24 hours in the event poHer. ! operation is continuing Hith tHo or more inoperable Control' rods or in the event poHer operation is continuing With one
-fully or partially withdrawn rod Which cannot -be moved :and
.for Hhich Control rod drive BeChanism damage has not been l ruled out...The surveillance need not be completed within 24 -
hours if the number of inoperable rods has been reduced to
.less than tHo and if it has been demonstrated that -control rod drive mechanism collet housing failure is not the cause of an immovable control rod.
i: O 4.2-1 1 i l l02
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l I l E. Surv:111tnca of th2 stendby liquid control system sh:11 be es follows I i
- 1. Pump operability Once/menth
- 2. Boron concentration determination Onec/ month
- 3. Functional test Each refueling outage
- 4. Solution volume and temperature check Once/ day F. At specific power operating conditions, the actual control rod configuration Hill be compared with the expected configuration based upon appropriately corrected past data.
This comparison shall be made every equivalent full power month. The initial rod inventory measurement performed when equilibrium conditions are established after a refueling or major core alteration Hill be used as data for reactivity monitoring during subsequent power operation throughout the fuel cycle. G. At power operating conditions, the actual control rod density Hill be Compared with the 3.5 percent control rod density included in Specification 3.2.B.6 This comparison shall be l made every equivalent full power month. H. The scram discharge volume drain and vent valves shall be verified open at least once per 31 days, except in shutdown mode *, and shall be cycled at least one complete cycle of full travel at least quarterly. I. All Hithdrawn control rods shall be determined OPERABLE by demonstrating the scram discharge volume drain and vent valves OPERABLE. This will be done at least once per refueling cycle by placing the mode sHitCh in shutdown and by verifying that: 1
- a. The drain and vent valves close within 60 seconds after receipt of a signal for control rods to scram, and
- b. The scram signal can be reset and the drain and vent valves open when the scram discharge volume trip is bypassed.
*These valves may be closed intermittently for testing under administrative I control.
Bases: The core reactivity limitation (Specification 3.2.A) requires that core reactivity be limited such that the core could be made suberitical at any time during the operating cycle, with the strongest operable control rod fully Hithdrawn and all other operable rods fully inserted. Compliance with this requirement can be demenstrated conveniently only at the time of refueling. Therefore, the demonstration must be such that it Hill apply to - the entire subsequent fuel cycle. The demonstration is performed Hith the reactor core in the cold, xenon-free condition and Hill show that the reactor is sub-critical at that time by at least R + 0.25% delta k with the highest Horth operable control rod fully Hithdrawn. 4.2-2
. O - I ?
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4 . _ . . ._ - _. . _ _ . _ ___. . _._ _ _ _ _ _ The value of R is th2 diffIre.nc2 betwe3n tHo C11CulatEd v31uss of reactivity of the cold, xenon-free core with the strongest operable control rod fully Hithdrawn. The reactivity value at the i beginning of life is subtracted from the maximum reactivity value anytime later in life to determine R, which must be a positive quantity or its value is conservatively taken as zero. The value < of R shall include the. potential shutdown margin loss assuming full B4C settling in all inverted tubes present in the core. The value 0.25% delta k in the expression R + 0.25% delta k serves at the beginning of life as a finite, demonstrable shutdown margin. This margin is demonstrated by full Hithdrawal of the strongest rod and partial withdrawal of a diagonally adjacent rod. to a position calculated to insert an R + 0.25% delta k reactivity. i Observation of subcriticality in this condition assures suberiticality Hith not only the strongest rod fully withdrawn but at least an R + 0.25% delta k margin beyond this. I The control rod drive housing support system (2) is not subject to deterioration during operation. Houever, reassembly must be assured following a partial or complete removal. The scram insertion tir es for all control rods (3) will be determined at the time of each refueling outage. The scram times generated at each refue).ing outage Hhen Compared to scram times previously recorded gives a measurement of the functional effects of deterioration for each control rod drive. The more frequent . scram insertion time measurements of eight selected rods are , performed on a representative sample basis,to monitor performance l and give an early indication of possible deterioration and l required maintenanca. The times given for the eight-rc$ tests are based on the testing experience of control rod drives which were O known to be in good condition. The weekly control rod exercise test serves as a periodic check against deterioration of the control rod system. Experience with this control red system has indicated that .Heckly tests are adequate, and that rods which move by drive. pressure- Hill scram when required as the pressure applied is much higher. The - frequency of exercising the control rods has been increased under the conditions of two or more control rods which are valved out of - 4 service in order to provide even further assurance of the reliability of the remaining control rods. Pump operability, boron concentration, solution temperature and volume of the standby liquid control system (4) are checked 'on~ a frequency consistent Hith instrumentation Checks. described in j Specification 4.1. Experience with similar systems has . indicated that the test frequencies are adequate. The only practical time , to functionally test the liquid control? system is during a refueling _ outage. The functional test . includes the' firing of 1 explosive charges to open the shear plug valves and the pumping of demineralized water into.the reactor,to assure operability of the system downstream of' the pumps. The . test.-also includes ] .
- recirculation of liquid control solution to and from the solution
' tanks.-
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Pump opertbility is demonstratrd on a more ferqu;nt basis. This test consists of recirculation of deminerali::ed Hater to a test tank. A continuity check of the firing circuit on the shear plug valves is provided by pilot lights in the control room. Tank level and temperature alarms are provided to alert the operator to off-normal conditions. The functional test and other surveillance on components, along Hith the monitoring instrumentation, gives a high reliability for standby liquid control system operability. The control rod inventory check provides detection of reactivity anomalies, and additional verificatich of control rod position at a frequency which is compatible with the time and power varying parameters being checked. References (1) FDSAR, Volume II, Figure III-5-11. (2) FDSAR, Volume I, Section VI-3. (3) FDSAR, Volume I, Section III-5 and Volume II, Appendix B. (4) FDSAR, Volume I, Section VI-4. 9 4.2-4 x3 ?_. ? " _--
4 . l 4.3 REACTOR COOLANT Applienbility: Applies to the surveillance requirements for the reactor coolant a system. Obiective: To determine the condition of the reactor coolant system and the operation of the safety devices related to it. Scecification: A. Neutron flux monitors shall be installed in the reactor j vessel adjacent to the vessel wall at the core midplane-level. The monitors shall be removed and tested at the first refueling outage to experimentally verify the calculated values of integrated neutron flux that are used to determine ' j the NDTT from Figure 0.3.1. B. Non-destructive extminations shall'be made on the components l as specified in Table 4.3.1. Any indication of a defect i shall be investigated and evaluated. C. .A visual examination for leaks shall be made with the reacter , coolant system at pressure during. each scheduled refueling. outage or after major repairs have been made to the reactor
- coolant system. The. requirements of Specification 3.3.A shall be met during the test.
D. Each replacement safety valve or valve that has been repaired shall be bench checked for the proper set point. A minimum of 5 of the valves.shall be bench checked or replaced Nith a bench checked valve each refueling outage such that all. valves are checked in three successive refueling outages, to insure set points are as folloHs: Number of Valves Set Point:(psic)-
-4 1212 = 12 4 1221 = 12 4' 1230 = 12.
4 - 1239 = 12 l - E. .A sample of reactor coolant shall be analyzed at least every. j ,72 hours for the purpose of -determining the content of , ch1P ide ion and to check the conductivity.
.F. . Periodic -leakage testing (a) on each valve listed in Table j 4.3.2 shall-be accomplished: prior to exceeding 600' psig I reactor . pressure every time the plant is placed on the cold- ,
i shutdown condition for refueling,~each. time the . plant, is placed in 1 a cold shutdown condition for 72 hours if testing d' 4.3-1
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his not be;n tecomplish d in the prac;eding 9 months, cnd prior to returning the valve to service after maintenance, repair or replacement work is performed. (a) To satisfy ALARA requirements, leakage may be measured indirectly (as from the performance of pressure indicators) if accomplished in accordance with approved procedures and supported by computations showing that the method is capable of demonstrating valve compliance Hith the leakage criteria. Bases: Humerous data are available relating integrated flux and the change in Nil-Ductility Transition Temperature (NDTT) in various steels. The base metal has been demonstrated to be relatively insensitive to neutron irradiction (see expected NDT changes in FDSAR Table IV-1-1, and Figures IV-2-9 and IV-2-10). The most conservative data has been used in Specification 3.3. The integrated flux at the vessel Hall is calculated from core physics data and Hill be measured using flux monitors installed inside the vessel. The measurements of the neutron flux at the vessel Hall Hill be used to check and if necessary correct, the calculated data to determine an accurate flux. From this a conservative NDT temperature can be determined. Since no shift Hill occur until an integrated flux of 1.0E17 nyt is reached, the confirmation can be made long before an HDTT shift would occur. Prior to operation the reactor coolant system Hill be free of gross defects and the facility has been designed such that gross j I defects should not occur throughout life; however, to determine ! the status of the coolant system to ensure that gross defects are not developing this surveillance program was developed. This inspection Hill reveal problem areas should they occur before a leak develops. In addition, extensive visual inspection for leaks Hill be made on critical systems. The inspection period is based on the observed rate of gronth of defects from fatigue studies sponsored by the AEC. These studies show that it requires thousands of stress cycles, at stresses beyond any conceived in a reactor system to propagate a crack and it is thus concluded that the frequency is adequate. The access provisions for in-service inspection has been compared with the access requirements of the proposed N-45 Code for In-Service Inspection of Nuclear Reactor l Coolant Systems. The degree of access required by N-45 is not l generally available, however, volumetric inspection of accessable areas has been proposed. It is considered appropriate to evaluate the results obtained from compliance with this Technical Specification and the state of the art before establishing a long term inspection program. Experience in safety valve operation shows that a check of approximately 1/3 of the safety valves per year is adequate to detect failures or deterioration. The tolerance value is specified in Section I of the ASME Code at plus or minus 1% of design pressure. An analysis has been performed which shows that - Hith all safety valves set 12 psig higher the safety limit of 1375 psig is not exceeded. Conductivity instruments continuously monitor the reactor coolant. Experience indicates that a check of the conductivity 4.3-2
- ~. . _ _ _ _ _ _ _ __ _
instrumentation Et least Every 72 hours is adequate to ensure-accurate _ readings. The reactor water sample will'also be used to
<stermine the chloride ion content to assure that the limits of
- i.3.E are not exceeded. The chloride ion content will not change
.ipidly over a period of'several days; therefore, the sampling-frequency is adequate. ,
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l 4.4 EMERGENCY COOLING Apolicability: Applies to surveillance requirements for the emergency cooling systems. Obiective: To verify the operability of the emergency cooling systems. Specification: Surveillance of the emergency cooling systems shall be performed as follows: Item Frequency A. Core Sprav System
- 1. Pump operability Once/ month. Also after major maintenance and prior to startup following a refueling outage.
~
- 2. Motor operated valve Once/ month cperability
- 3. Automatic actuation test Every 3 months
- 4. Pump co=partment water- Once/Heek and after each entry tight doors closed
- 5. Core spray header delta P instrumentation check Once/ day calibrate Once/3 months test Once/3 months B. Automatic Deeressurization
- 1. Valve operability Every refueling outage l
- 2. Automatic actuation test Every refueling outage l
l C. Containment Cooling System Once/ month. Also, after major
^
- 1. Pu=p operability maintenance and prior to startup -
following a refueling cutage.
- 2. Automatic actuation test Every 3 months
- 3. Pu=p compartment water- Once/Heek and after each entry tight doors closed 4.4-1
- d I l'
- D. Emeroency Service Water System
- 1. Pump operability Once/ month. Also after major O
maintenance and prior to startup following refueling outage.
- 2. Automatic actuation test Every 3 months E. Control Rod Drive Hydraulic System
- 1. Pump operability Once/ month. Also after major
' maintenance and prior to startup ,
following a refueling outage. F. Fire Protection System
- 1. Pump and Isolation Once/ month. Also after major valve operability maintenance and prior to startup
' following a refueling outage. Bases: It is during major maintenance or repair that a system's design intent may be violated accidentally. Therefore, a functional test is required after every major maintenance operation. During an , 1 extended outage, such as a refueling outage, major repair and maintenance may be performed on many systems. To be sure that , these repairs on other systems do not encroach unintentionally on critical standby cooling systems, they should be given a i functional test prior to startup.
! Hotor operated pumps, valves and other active devices that are normally on standby should be exercised periodically to make sure that they are free ~to operate. Motors on pumps should operate long enough to approach equilibrium temperature to ensure there is no overheat problem. Whenever practical, valves should be stoked full length to ensure that nothing impedes. their motion.
Engineering judgment based on experience and availability analyses.
- of the type presented in Appendix L of the FDSAR indicates that; I
l testing these components more often than once a month over a long-period of time - does not significantly , improve the' system
, reliability. Also. at this fre not be a problem through the life'quencyof the plant. of testing wearout should , During tests of the electromatic relief valves, steam from the
! reactor vessel will be discharged directly to: the. absorption-chamber pool. Scheduling the- tests 1in conjunction' with the j refueling outage permits the tests to be run at low pressure thus ! minimizing the stress on the system. The control rod drive hydraulic system is normally in operation, thereby providing continuous indication'of system operability. A f, check of ficw . rate .and operability. can be made during normal-operation.' , i 4.4-2 D n- a -
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4.5 CONTAINME'!T SYSTEM Acplicability: Applies to the containment system leakage rate, filter efficiency and inerting. Obiective: To verify that the condition of the containment system and the leakage from the containment system are maintained within specified values. Seccification: A. Inteagated Primary Contcinment Leakace Rcte Test
- 1. Integrated leak rate shall be performed prior to initial plant operation at the test pressures of 35 psig (Pp) and the test pressure (Pt) of 20 psig to obtain the respective measured. leak rates Lm (35) and Lm (20).
- 2. Subsequent leakage rate tests shall be performed Hithout preliminary leak detection surveys or leak repairs immediately prior to or during the test, at nr. initial pressure of approximately 20 psig.
O. Leak repairs, if necessary to permit integrated leakage rate testing, shall be preceded by local leakage measurements. The leakage rate difference, prior to and after repair when corrected to Pt shall be added to the final integrated leakage rate result.
- 4. Closure of the containment isolation valves for the purpose of the test shall be accomplished by the means provided for normal operation of the valves.
- 5. The test duration shall not be less than 24 hours for integrated leak rate measurements, but shall be extended to a sufficient period of time to verify, by measuring the quanity of air required to return to the starting point (or other methods of equivalent sensitivity), the validity and accuracy of the leakage rate results.
B. Accentence Criteria
- 1. The maximum allowable leakage rate Lp shall not exceed 1.0 Height percent of the contained air per 24 hours at the test pressure of 35 psig (Pp). .
- 2. The allowable test leak rate Lt (20) shall not exceed the lesser value established as follows:
Lt (20) = 1.0 Lm (20)/Lm (35) 4.5-1 O I l' g =:- --
or
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Lt (20) = 1.0 SQ RT ((Pt(20))/(Pt(35)))
) 3. 7he allowable operational leak rate, Lto (20) which shall be met prior to resumption of power operation following a test (either as measured or following repairs and retest) shall not exceed 0.75 Lt (20).
C. Corrective Action If leak repairs are necessary to meet the allowable operational leak rate, the integrated leak rate test need not be repeated provided local leakage measurements are conducted, and the leak rate differences prior to and after repairs when corrected to Pt and deducted from the integrated leak rate measurement, yield a leakage rat < value not in excess of the allowable operational leak rate Lto(20). D Frecuency Integrated lesk rate tests shall be performed Hithin plus or minus 8 months as follows:
- 1. During the first refueling outage after initial criticality or 12 months, Hhichever is sooner.
- 2. Within 24 months from the date of the test in "1" above.
- 3. Within every 48 months from the date of the test in "2" and every 48 months thereafter.
In the event the leak rate of any test exceeds the allowable test leak rate Lt(20), the condition shall be corrected, the testing frequency shall revert to the following schedule, Hithin plus or minus 8 months, as follows:
- 1. Within 12 months following the retest made (local or integrated) to correct excess leak rate.
- 2. Within 24 months of Test 1.
- 3. Within 48 months of Test 2.
E. Local Leak Rate Tests 1.- Primary containment testable penetrations and isolation valves shall be tested _at a . pressure of 35 psig each refueling outage except bolted double-gasketed seals shall be tested whenever the seal is closed after being opened, and at. least at each refueling outage. .
- 2. ' Personnel air ' lock door seals shall be tested at-a-pressure of 10 psig each refueling outage.
- 3. _ Containment components not' included in 1, and 2, which required leak repairs following any integrated leakage rates
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in ord2r to mest tha c11owib13 11:kag3 rats unit Lt chall be subjected to local leak tests at a pressure of 35 psig at each refueling outage.
- 4. The main steam line isolation valves are to be tested at a pressure of 20 psig during each refueling outage.
F. Corrective Action
- 1. If the total leakage rates listed below as adjusted to a test pressure of 20 psig, are exceeded, repairs and retests shall be performed to correct the condition.
- a. Double gasketed seals 10% Lto (20)
- b. Testable penetrations and isolation valves 30% Lto (20)
- c. Primary containment air purge penetrations and reactor building to torus vacuum relief valves 50% Lto (20)
- d. Any one penetration or isolation valve 5% Lto (20)
G. Continuous Leak Rate Monitor
- 1. When the primary containment is inerted the containment shall be continuously monitored for gross leakage by review of the inerting system makeup requirements.
- 2. This monitoring system may be taken out of service for the purpose of maintenance or testing but shall be returned to service as soon as practical.
H. Report of Test Results Each integrated leakage rate test shall be the subject of a summary technical report, including results of the local leakage rate test. The report shall include analysis and interpretation of the results which demonstrate compliance in meeting the specified leakage rate limits. I. Functional Test of Valves l l 1. All containment isolation valves specified in Table 3.5.2 shall be tested for automatic closure by an isolation signal during each refueling outage. The following valves are required to close in the time specified below: greater or equal to 3 sec. and Main steam line isolation valves less than or equal to 10 sec. Isolation condenser isolation valves less than or equal to 60 sec.
- 4. 5-3
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Cleanup system isolation valves less than or equal to 60 sec. Cleanup auxiliary pumps system isolation valves less than or equal to 60 sec. Shutdown system
, isolation valves less than or equal to 60 sec.
- 2. Each containment isolation valve shown in Table 3.5.2 shall be demonstrated operable price to returning the valve to service after maintenance, repair or replacement Hork is performed on the valve or its as'sociated actuator by cycling the valve through at least one complete cycle of full travel and verifying the specified isolating time. Following maintenance, repair or replacement work on the control or power circuit for the valves shown in Table 3.5.2, the affected component shall be tested to assure it will perform its intended function in the circuit.
- 3. During periods of sustained power operation each main steamline isolation valve shall be exercised in accordance with the following schedule.
- a. Daily tests - Exercise valve (one at a time) to approximately 95% open position with reactor at operation power level,
- b. Guarterly tests - Trip valve (one at a time) and check full closure time, with reactor power not greater than 50% of rated power.
- 4. Reactor Building to Suceression Chamber Vacuum Breakers
- a. The reactor building to suppression chamber vacuum breakers and associated instrumention, including set point, shall be checked for proper operation every three months.
- b. During each refueling outage each vacuum breaker shall be tested to determine that the force required to open the vacuum breaker from closed to fully open does not exceed the force specified in Specification 3.5.A.4.a. The air-operated vacuum breaker l instrumentation shall be calibrated during each refueling outage.
- 5. Pressure Suppression Chamber - Devuell Vacuum Breakers
- a. Periodic Operability Tests Once each month and following any release of energy Hhich Hould tend to increase pressure to the suppression chamber, each operable suppression chamber - dryHell vacuum breaker shall be exercised. Operation of position switches, indicators and alarms shall be O 4.5-4 I l'
verifi d monthly by oper; tion of e;ch oper:bl3 vacuum breaker,
- b. Refuelina Outace Tests (1) All suppression chamber -
dryHell vacuum breakers shall be tested to determine the force required to open each valve from fully closed to fully open. (2) The suppression chamber - drywell vacuum
~
breaker position indication and alarm systems shall be calibrated and functionally tested. (3) At least four of the suppression chamber - dryHell vacuum breakers shall be inspected. If deficiencies are found, all vacuum breakers shall be inspected and deficiencies corrected such that Specification 3.5.A.4.a can be met. (4) A drywell to suppression chamber leak rate test ': hall demonstrate that with an initici differential pressure of not less than 1.0 psi, the differential pressure decay rate shall not exceed the equivalent of air flow through a 2-inch orifice. J. Reactor Building
- 1. Secondary containment capability tests shall be conducted after isolating the reactor building and placing either Standby Gas Treatment System filter train in operation.
- 2. The tests shall be performed at least once per operating cycle and shall demonstrate the capability to maintain a 1/4 inch of water vacuum under calm Hind conditions with a Standby Gas Treatment System Filter train flow rate of not more than 4000 cfm.
- 3. A secondary containment capability test shall be conducted at each refueling outage prior to refueling.
- 4. The results of the secondary containment capability tests shall be in the subject of a summary technical report which can be included in the reports specified in Section 6.
K. Standby Gas Treatment System
- 1. The capability of each Standby Gas Treatment System circuit shall be demonstrated by: .
- a. At least once per 18 months, after every 720 hours of operation, and following significant painting, fire, or chemical release in the reactor building during operation of the Standby Gas Treatment System by verifying that:
4.5-5 O
- I l' :i
~ _ - __ m + j
s. (1)- Th2 chircoal absorbers ramova greater than or equal to 99% of a .halogenated hydrocarbon refrigerant test gas 'and the HEPA filters remove greater than or equal to 99% of the DOP in a cold DOP test when tested in accordance Hith ANSI H5A3-1975. (2) Results 'of laboratory carbon sample analysis-show greater than- or equal to 90% radioactive methyl iodine removal- efficiency when 0tested in accordance with ASTM D 3803-79 ( 30 C, 95% relative humidity).
- b. At least once per 18 months by demonstrating:
(1) That the presc :re drop across a HEPA filter is equal to or less than_ the maximum allowable pressure drop indicated in Figure 4.5.1. (2) The inlet heater is capable of at.least 10.9 KH input. 2
- (3) Operation Hith a total floH Hithin 10% of i design floH.
' c. ' At least once per 30 days on a STAGGERED TEST BASIS by operating each circuit for a minimum of'10 hours.
- d. Anytime the HEPA filter. bank or :the charcoal absorbers have been partially or completely' replaced, the test for '4.5.k.1.a. Hill be performed prior to.
returning the system to OPERABLE STATUS. , e. Automatic initiation of each circuit every 18 , months. L. Deleted M. Inertina surveillance j When an inert atmosphere is required in ~ the ' primary. containment the oxygen concentration in the- primary containment shall he checked at least weekly. H. DevHell'Co;# h g ervalliance ,
-i Carbon E:41 r.t panels coated Hith Fire-bar D shall ber '
iplaced iy,ide the 4ryHell near the : reactor. coremidplant -l level. They shall. be removed for visual observation and= l Height loss measurements during the first, second, fourth and .] eighth refueling outages. -i l } s. 4.5-6 i i-Mn , ,; , __ 5
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- 0. Instrument Line Flen Chee!r valves Surveillane, The capability of each instrument line flow check valve to isolate shall be tested at least once in every period between refueling outages. Each time an instrument line is returned to service after any condition which could have produced a pressure or flow disturbance in that line, the open position of the flow check valve in that line shall be verified. Such conditions include:
Leakage at instrument fittings and valves Venting an instrument or instrument line Isolating an instrument Flushing or draining an instrirment. P. Suppression Chamber Surveillance
- 1. At least once per day the suppression chamber water level and temperature and pressure suppression system pressure shall be checked.
- 2. A visual inspection of the suppression chamber interior, including Hater line regions, shall be made at each major refueling outage.
- 3. Whenever heat from relief valve operation is being added to the suppression pool, the pool temperature shall be continually monitored and also observed until the heat addition is terminated.
- 4. Whenever operation of a relief valve is indicated and the suppression pool temperature reaches 160"F or above while
_ the reactor primary coolant system pressure is greater than 180 psig, an external visual examination of the suppression chamber shall be made before resuming normal power operation. [
- 5. Drywell-Suppression Chancer Differential Pressure
- a. The pressure differential between the drywell and suppression chamber shall be recorded at least once per shift when the primary containment is required to be inerted by Specification 3.5.A.9.a.
- b. Instrumentation to- measure the drywell to suppression chamber differential pressure and suppression chamber water level shall be calibrated once every 6 months.
Q. Shock Suppressors (Snubbers) -
- 1. All hydraulic snubbers listed in Table 3.5.1 whose seal material has been demonstrated by operating experience, lab testing or analysis to_ be' compatable Hith the operating environment shall be visually inspected. This inspection
~
4.5-7 l' 4 e:- m -- - I
shall include, but not necessarily be limited to, inspection of hydraulic fluid reservoir, fluid connections, and linkage connections to the piping and anchor to verify snubber operability in accordance Hith the fo11 cuing schedule: Number of Snubbers Found Incperable During Inspection Next Required or Durina Inspection Interval Inspection Interval 0 18 months plus or minus 25% 1 12 months plus or minus 25% 2 6 months plus or minus 25% 3, 4 124 days plus or minus 25% 5, 6, 7 62 days plus or minus 25% greater than or equal to 8 31 days plus er minus 25% The required inspection interval shall not be lengthened more than one step at a time. Snubbers may be categorized in tHo groups, " Accessible" or
" Inaccessible" based on their accessibility for inspection during reactor operation. These two groups may be inspected independently according to the above schedule.
- 2. The initial inspection shall be perfermed within 12 months from the date of issuance of these specifications.
For the purpose of entering the schedule into Specification 4.5.Q.1, it shall be assumed that the facility had been on a 12 month inspection schedule.
- 3. All hydraulic snubbers whose seal materials have not been demonstrated to be compatible with the cperating environment shall be visually inspected for operability every 31 days except when in the shutdown or refuel mode.
- 4. Once each refueling cycle, a representative sample of 10 hydraulic snubbers or approximately 10% of the hydraulic snubbers, whichever is less, shall be functionally tested for operability including verification of proper piston movement, lock up and bleed. For each unit and subsequent unit found inoperable, an additional 10% or 10 hydraulic snubbers shall be so tested until no more failures are found or all units have been tested. Snubbers of rated capacity greater than 50,000 lb. need not be functionally tested.
Bases: The primary containment preoperational test pressures are based I upon the calculated primary containment pressure response in the event of a loss-of-coolant accident. The peak dryuell pressure would be 38 psig Hhich Hould rapidly reduce to 20 psig Hithin 100 seconds folloHing the pipe break. The total time the dryHell pressure would be above 35 psig is calculated to be about 7 seconds. Following the pipe break adsorption chamber pressure rises to 20 psig Hithin 8 seconds, equalizes Hith dryHell pressure at 25 psig within 60 seconds and thereafter rapidly decays with the,dryuell pressure decay. (1) O 4.5-8
. _ - _._ _ _.m . , . _ , ,s_
.1 18 l
The design pr:ssures of thm dryn:11 cnd absorption chamber ars 62 psig and 35 psig, respectively. (2) The design leak rate is 0.5%/ day at a pressure of 35 psig. As pointed cut above, the pressure response of the drywell and absorption chamber following an accident would be the same after about 60 seconds. Based on the calculated primary containment pressure response . discussed above and the absorption chamber design pressure, primary containment preoperational test pressures were chosen. Also, based on the primary containment pressure response and the fact that the drywell and absorption chamber function as a unit, the primary containment will be tested as a unit rather than testing the individual components separately. The design basis loss-of-coolant accident was evaluated at the primary containment maximum allowable accident leak rate cf 1.0%/ day at 35 psig. The analysis showed that with this leak rate and a standby gas treatment system filter efficiency of 90% for halogens, 95% for particulates, and assuming the fission products release fractions stated in TID-14844, the maximum total whole body passing cloud dose is about 10 rem and tha maximum total thyroid dose is about 139 rem at the site boundary censidering fumigatien conditions over an exposure duration of two hours. The resultant doses that would occur for the duration of the accident at the low population distance of 2 miles are lower than those stated due to the variability of meteorological conditions that would be expected to occur over a 30-day period. Thus, the doses reported are the maximum that would be expected in the unlikely event of a design basis loss-of-coolant accident. These doses are also based on the assumption of no holdup in the secondary containment resulting in a direct release of fission product from the primary containment through the filters and the stack to the environs. Therefore, the specified primary containment leak rate and filter efficiency are conservative and provide margin between expected offsite doses and 10 CFR 100 guideline limits. Although the dose calculations suggest that the allowable test leak rate could be allowed to increase to about 2.0%/ day before the guideline thyroid dose limit given in 10 CFR 100 Hould be exceeded, establishing the limit at 1.0%/ day provides an adequate margin of safety to assure the health and safety of the general public. It is further considered that the alloHable leak rate should not deviate significantly from the containment design value to take advantage of the design leak-tightness capability of the structure over its service lifetime. Additional margin to maintain the containment in the "as built" condition is achieved by establishing the allowable operational leak rate. The l operational limit is derived by multiplying the allowable test l 1eak rate by 0.75 thereby providing a 25% margin to allow for leakage deterioration which may occur during the period between leak rate tests. The primary containment leak rate test frequency is based on maintaining adequate assurance that the leak rate remains within the specification. The leak rate test frequency is based on the AEC guide for developing leak rate testing and surveillance of reactor containment vessels. (4) Allowing the test intervals to 4.5-9 e I l'
+ c , , .
be Extend:d up to 8 months permits some f1:xibility nendid to havn the tests coincide with scheduled er unscheduled shutdown periods, p The penetration cnd air purge piping leakage test frequency, along Q Hith the containment leak rate tests, is adequate to allcw - detection of leakage trends. Whenever a double gasketed penetration (primary containment head equipment hatches and the absorption chamber access hatch) is broken and remade, the space between the gaskets is pressurized to determine that the seals are performing properly. The test pressure of 35 psig is consistent with the accident analyses and the maximum preoperational leak rate test pressure. If the leakage rates of the double gasketed seal penetrations, testable penetration isolation valves, containment air purge inlets and outlets and the vacuum relief l valves are at the maximum specified, they Hill total 90 percent of the allowed leak rate. (5) Hence 10% margin is left for leakage through Halls and untested components. Monitoring the nitrogen makeup requirements of the inerting system provides a method of observing leak rate trends and would detect gross leaks in a very short time. This equipment must be periodically removed from service for test and maintenance, but this out-of-service time Hill be kept to a practical minimum. The containment integrity isolation valves are provided to maintain containment integrity following the design basis loss-of-coolant accident. The closure times of the isolation valves on the containment are not critical because it is on the order of minutes before significant fission product release to the containment atmosphere for the design basis loss of coolant. These valves are highly reliable, see infrequent service and most of them are normally in the closed position. Therefore a test during each refueling outage is sufficient. (6) Large lines connecting to the reactor coolant system, whose failure could result in uncovering the reacter core, are supplied with automatic isolation valves (except containment cooling). The specified closure times are adequate to restrict the coolant loss from the circumferential rupture of any of these lines outside the containment to less than that for - a main steam line rupture. Therefore, this isolation valve ' closure time is sufficient to prevent uncovering the core. (7) Since the main steam line_ isolation valves are normally in the-open position, more frequent testing is specified. Daily exercising the valves to about the 95% open position provides assurance of their operability and the quarterly full closure test provides assurance that the valves maintain the required closing time. The minimum time of 3 seconds is based on the transient analysis 'of the isolation valve closure that shows the pressure peak 76 psig beloH the lowest safety valve setting. The maximum time of - 10 seconds provides ~ a 0.5 second margin to the 10.5 - seconds that is assumed for the main steam line break dose calulations. Surveillance of- the suppression chamber-reactor building vacuum breakers consists of operability checks- and. leakage' tests wb 4.5-10'
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(conduct:d es part of the contrinment leak - tightness trsts). These vacuum breakers are normally in a closed position and open only during tests or an accident condition. As a result, a testing frequency of three months for operability is considered . justified for this equipment. Inspections and calibrations are performed during the refueling outages, this frequency being based on equipment quality, experience, and engineering judgment. The fourteen suppression chamber-drywell vacuum relief valves are designed to open to the full open position (the position that curtain area is equivalent to valve bore) with a force equivalent to a 0.5 psi differential acting on the suppression chamber face of the valve disk. This opening specification assures that the design limit of 2.0 psid between the drywell and external environment is not exceeded. Once each refueling outage each valve is tested to assure that it will open fully in response to a force less than that specified. Also it is inspected to assure that it closes freely and operates properiv. The containment design has been examined to establish the allowable bypass area between the drywell and suppression chamber as 10.5 square inches (expressed as vacuum breaker open area). This is equivalent to one vacuum breaker disk off its seat 0.371 inch; this length corresponds to an angular displacement of 1.258. A conservative alloHance of 0.10 inch has been selected as the maximum permis::ible valve opening. Valve closure within this limit may be determined by light indication from two independent position detection and indication systems. Either system provides a control room alarm for a non-seated valve. At the end of each refueling cycle, a leak rate test shall be performed to verify that significant leakage flow paths do not exist between the drywell and suppression chamber. The drywell pressure will be increased by at least i psi with respect to the suppression chamber pressure. The pressure transient (if any) will be monitored with a sensitive pressure gauge. If the drywell pressure cannot be increased by 1 psi over the suppression chamber pressure it would be because a significant leakage path exists; in this event the leakage source will be identified and eliminated before power operation is resumed. If the dryHell pressure C3D be increased by 1 psi over the suppresion chamber the rate of change of the suppression chamber pressure must not exceed a rate equivalent to the rate of air flow from the drywell to the suppression chamber through a 2-inch orifice. In the event the rate of change of pressure exceeds this value, then the source of leakage will be identified and eliminated before power operation is resumed. The drywell-suppression chamber vacuum breakers are exercised monthly and immediately following termination of discharge of , steam into the suppression chamber. This monitoring of valve operability is intended to assure that valve operability and position indication system performance does not degrade between refueling inspections. When a vacuum breaker valve is exercised through. an opening-closing cycle, the position indicating lights are designed to function as follows: 4.5-11 O
- I l' L. . _ . _
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r .; Full Closed 2 Green - On (Closed to 0.10" open) 2 Red - Off , 1 l Open 0.10"- 2 Green - Off
- t. (0.10" open to full open) 2 Red - On During each refueling outage, four suppression chamber-dryHell
.. Vacuum breakers Hill be inspected to assure components have not deteriorated. Since' valve internrls are designed for'a 40-year lifetime, an inspection pregram Hhich cycles through all valves in about' one-tenth of the design lifetime is extremely conservative. The alarm systems for the vacuum breakers will be . calibrated during each refueling outage. This frequency is based on j experience and engineering judgement. l Initiating reactor building isolation and operation of the standby gas treatment system to maintain a 1/4 inch of Hater vacuum, tests the operation of the reacter building isolation valves, leakage i tightness of the reactor building and performance of the standby l gas treatment system. Checking the initiating sensors and
- associated trip channels demonstrates the capability for automatic-actuation. Performing the reactor building in leakage test. prior to refueling demonstrates secondary containment capability prior to extensive fuel handling operations associated With the outage.
Verifying the efficiency and operation of charcoalt filters once per 18 months gives sufficient confidence of standby' gas treatment system performance capability. A charcoal filter efficiency of-99% for halogen removal is adequate. , The in-place testing of charcoal filters is performed using Freen-112* Nhich is injected into the system upstream of the charcoal s filters. Measurement of the ; Freon concentration upstream and doHnstream of the charcoal filters is: made using 'a . gas chromatograph. The . ratio of the inlet and outlet concentrations gives an overall indication of the leak tightness of the system. Although this is basically a' leak test, since the filters have 4 charcoal of known efficiency and holding capacity for elemental iodine and/or methyl iodide, the test also gives an indication:of the relative efficiency =of~ the installed system. The test procedure is an' adaptation of test procedures developed at the Savannah River laboratory which Here described in' the Ninth AEC-Air Cleaning Conference.** High efficiency particulate filters are installed before -and after the charcoal filters - to minimize potential release- of_ _particulatesL to-:the. environment 'and to-prevent clogging of the iodine filters. An efficiency of 99%.Lis; adequate to retain particulates ,thatj may be-_ released to.the: reactor building-folloHing an accident. This will be demonstrated by testing with DOP at testing medium.
- Trade name of.E. I.'duPont de'Nemours_& Company'
**D'-R 'Huhbaier, "In Place Hondestructive Leak Test for Iodine-Absorbers,-
-Proceedings of the 9th AEC Air Cleaning Conf, USAEC Rept Conf-660904, 1966 2 .-
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If laboratory tests for the adsorber material in one circuit of the Standby Gas Treatment System are unacceptable, all adsorber material in that circuit shall be replaced Hith adsorbent qualified according to Regulatory Guide 1.52. Any HEPA filters _ found defective shall be replaced with -those qualified with - Regulatory Position C.3.d of Regulatory Guide 1.52. The snubber inspection frequency is based upon maintaining a constant level of snubber protection. Thus, the required inspection interval varies inversely with the observed snubber failures. The number of inoperable snubbers found during a required inspection determines the time interval for the next required inspection. Inspections per' formed 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 (normal time less 25%) may not be used to lengthen the inspection interval. Any inspection whose results require a shorter inspection interval Hill override the previous schedule. Experience at operating facilities has shown that the required surveillance program should assure an acceptable level of snubber performance provided that the seal materials are compatible with the operating environment. Snubber containing seal material which has not been demonstrated by operating experience, inb tests or analysis to be compatible Hith the operating environment should be inspected more frequently (every month) until material compatibility is confirmed or an appropriate changeout is completed. To further increase the assurance of snubber reliability, functional tests should be performed once each refueling cycle. These tests will include stroking of the snubbers to verify proper piston movement, lock-up and bleed. Ten percent or ten snubbers, whichever is less, represents an adequate sample for such tests. Observed failures of these samples should require testing of additional units. Snubbers in high radiation areas or those especially difficult to remove (see Table 3.5.1) need not be selected for functional tests provided operability was previously verified. Snubbers of rated capacity greater than 50,000 lb. are exempt from the functional testing requirements because of the inpracticability of testing such large units. After the containment oxygen concentration has been reduced to meet the specification initially, the containment atmosphere is maintained above atmospheric pressure by the primary containment inertir.g system. This system supplies nitrogen makeup to the containment so that the very slight leakage from the containment is replaced by - nitrogen, further reducing the oxygen concentration. In addition, the oxygen concentration is concentration is
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continuously recorded and high oxygen annunciated. Therefore, a weekly check of oxygen concentration is adequate. This system also provides capability for determining if there is gross leakage from the containment. 4.5-13
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The dryw211 Exterior Hos,ccated Hith Firsbar D prior to conersta pouring during construction.The Firebar D separated the drywell steel. plate .from the concrete. After installation, the drywell-liner.Has heated and expanded to compress the Firebar D to supply
-C a gap between -the steel dryuc11 and the concrete. The gap prevents contact of the drywell Hall with the concrete Hhich might
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cause excessive local stresses during drywell expansion in a loss-of-coolant accident. The surveillance program is being e.nducted to demonstrate that the Firebar D will maintain its integrity and not deteriorate throughout plant life. The surveillance frequency is adequate to detect any deterioration tendency of the material. (0) The operability of the instrument line flow check valves are demonstrated to assure isolation. capability for excess floH and to assure the operability of the instrument sensor when requeired. Because of the large, volume and thermal capacity of the suppression pool, the volume and temperature normally changes very slowly and monitering .these parameters -daily is sufficient to establish any temperature trends. By requiring the suppression pool temperature to be continually monitored and also observed during periods of significant heat addition, the. temperature trends will be closely followed so that appropriate action can be 1 taken. The requirement for an external visual examination following any event Hhere potentially high leakings could occur provides assurance that no significant damage was encountered. Pcrticular attention should be focused on- structural discontinuities in the vicinity of- the relief valve discharge i since these are expected to be the points of highest stress.
- References (1) Licensing Application, Amendment 32, Question 3.
(2) FDSAR, Volume I, Section V-1.1. (3) Deleted (4) Technical Safety Guide, " Reactor' Containment ~ Leakage Testing and Surveillance Requirements", USAEC Division of Safety Standards, Revised Draft, December. 15,'1966. (5) FDSAR, Volume I, Seetions,V-1.5 and'V-1.6. l (6) FDSAR, Volume I, Sections V-1.6 and XIII-3.4. ' (7) FDSAR,VolumeI,[SectionXIII-2. (8). Licensing Application, A'mendment'11,i Quest! ion III-18.
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4.6 RADIOACTIVE EFTLUENTS Applicability: Applies to monitoring of the gaseous and liquid radioactive effluents of the facility. Obiective: To verify that discharge of radioactive effluents to the envircnment is kept to a practical minimum and, in any event, within the limits of 10 CFR 20. Specification: A. The stack gas and radHaste liquid effluent radiation monitoring channels shall be checked daily, tested monthly, and calibrated every 3 months. B. (1) Stack Release (a) Station records of gross stack release rate of gaseous activity and meteorological conditions shall be maintained on an hourly basis to assure that the specified rates are not exceeded, to provide data for calculating offsite dose and to yield information concerning general integrity of the fuel cladding. (b) Within one month after issuance of these specifications and within one month following refuelings, an isotopic analysis Hill be made of a gaseous activity release sample Hhich identifies at least 90 percent of the total activity. From this sample, a ratio of long-lived (greater than 8 day half-life) and short-lived activity Hill be established. (c) Samples of off-gas Hill be taken at least every 96 hours and a gross ratio of long-lived (greater than 8 day half-life) and short-lived activity determined. (d) An isotopic analysis of off-gas will be performed monthly unless the ratio determined in (c) differs from the ratio established by the previous isotopic analysis by more than 20 percent. If this occurs, a new isotopic analysis shall be performed. (e) Gaseous release of tritium shall be measured at least quarterly.
^
(f) Station records of stack release of iodines and particulates Hith half-lives greater than eight days shall be maintained on the basis of all filter cartridges counted. 4.6-1 O - i i l'
(g) These cartridges shall be analyzed Heekly for gross alpha, beta and gamma activity, Ba-140, La-140 and I-131 when the iodine or particulate release rate is less than 4 percent of the maximum release rate given in 6 Specification 3.6.A(2), otherHise the cartridges shall be re=oved for analysis twice a week. (h) When the gross gaseous release rate exceeds 1% of the maximum release rate given in specification 3.6.A(1) and the average daily gross activity release rate increased by 50% over the previous full operating day, the cartridges shall be analyzed to determine the release rate increase for iodines and particulates. (i) An isotopic analysis of iodines and particulate radionuclides shall be performed at least quarterly. (2) Liquid Release (a) Station records shall be maintained of the radioactive concentration and volu=e before diluation of each batch of liquid effluent released and of the average dilution flow and length of time over which each discharge occurred. . (b) A weekly proportional composite
- of samples of each batch discharged during the week shall be analyzed for gross alpha, beta and gamma activity, Ba-140, La-140, I-131, dissolved gases such as Xe-133 and other shorter lived radionuclides (half-lives of 15 days er less)
G which are associated with routes of potential exposure to man. (c) A monthly proportional composite of samples of each batch discharged during the month shall be analyzed for _ gross alpha, beta and gamma activity, tritium and the principal gamma emitting fission and activation products in the sample, including lenger lived radionuclides associated with routes of potential exposure to man. The analysis should account for. at least 90% of the total activity, exclusive of tritium and dissolved gases, and should include at least Cs-137, Cs-134, Co-60, Co-58, Cr-51, Mn-54 and 2n-65. (d) A quarterly proportional composite shall be analyzed for SR-90. (e) Each batch of liquid effluent released shall be analyzed for gross alpha, beta and gamma activiy and the results recorded. Should there be any unexplained significant changes in gross alpha, beta or gamma activity from previous isotopic analyses, a new isotopic - analysis shall be performed.
*A proportional composite is one in which the quantity of liquid added to the composite is propertioned to the quantity of liquid in the batch that was released.
4.6-2 I l' :
(f) If a batch is to be raleased on an identified radionuclide basis, the analysis shall also include a gamma scan. If gamma peaks different from those determined by previous isotopic analyses are found or if the mixture concentration is greater than 10%.of the mixture MFC, a new isotopic analysis shall be . performed and recorded. (3) Environmental Procram The environmental program described in Section B.11.6 of Amendment 65 to the Application for a Reactor Operating License shall be conducted. The sampling frequencies specified in Table B-II-1 of Amendment 65 shall be adhered to as closely as conditions permit. C. A sample of reactor coolant shall be analyzed at least every 72 hours to determine total radioactive iodine content. D. Liquids contained in the waste sample tanks, floor drain sample tanks, and the waste surge shall be sampled and analyzed at least every 72 hours to determine the total activity in curies unless a tank has been valved out of service after determining its radioactive content. E. The operability of all equipment installed for the treatment of liquid wastes shall be verified at least once per quarter. F. The calculations specified in section 3.6.F shall be performed at least once per month. Bases: The check, test, and calibration requirements are specified to detect possible equipment failure and to show that maximum permissible release rates are not exceeded. The monitors (1) operate continuously and by virtue of normal plant operation, the operators daily observe that the instruments are performing. Failure of an instrument is evident, because of upscale, downscole, or loss of voltage alarms. The monitor trip points may be readily checked by a built-in pushbutton operated circuit. A portable test source may be affixed to the detector to re-establish c.alibration. Experience with instrument drift and failure modes indicates that the specified test frequency is adequate and consistent with other instrumentation. Continuous monitoring of the gaseous and collection of the particulate stack effluents provides the means for determining that the limits of Specification 3.6.A are not exceeded and for recording the actual levels of radioactivity that are being released from the stack. The frequencies of filter and cartridge analyses and isotopic analyses are specified to assure proper l identification of the isotopes being released. The sampling and ' l analysis of each batch of the radioactive liquid effluent provide ! the means for determining the release rate to the discharge canal to assure the limits of Specification 3.6.P Are not exceeded. The isotopic analyses of the weekly v monthly proportional composites of liquid waste samples provide de data for recording 4.6-3 9 l' l. -(
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and reporting tha cverage concentrations of radioactivity and total radioactivity released from the discharge canal. These isotopic analyses shall also provide the- normal means for calibrating gross alpha, beta and gamma analyses that are used to determine the concentration of batch for discharge on an unidentified basis. More frequent isotopic analyses .shc11 be required in conformance Hith 4.6.B.2 (e) & (f) to assure that the calibration of gross counts has not been altered by a change in the mixture of radioisotopes. The release of effluents on an identified radionuclide basis shall be based on the isctopic analysis of a typical Haste batch provided that the gross counting . analysis and the gamma scan indicate no significant change in the mixture constituents or the resultant mixture after dilution does not exceed 10 percent of the mixture MPC. If either of these tHo conditions occur, an isotcpic analysis of the batch to be discharged shall be performed. A minimum dilution factor for the isotopic mixture shall be determined using the following formula: Minimum D.F. = C1/MPC1 + C2/MPC2 + ... + Cn/MPCn Htere: C1 = Concentration of isotope 1, etc. MPC1 = MFC of isotope 1 from Appendix B, Table II, Column 2, 10 CFR 20, etc. Cn = Will normally be the concentration of unidentified activity remaining after identification of isotopes. This dilution factor can be expressed as a MPC for.the isotopic mixture thus: Mixture MPC =(Gross concentration / Minimum D.F.) This mixture MPC shall be used to _ determine the appropriate
-discharge rates and dilution for Haste' batches but can only; be used for the particular mixture as determined above.
Sampling of the radioactive . liquids contained in the radHaste. tanks located outside the radHaste facility Hill be used to essure that the limit of Specification 3.6.C is not exceeded. Due to normal ~ decay, a tank needs to be sampled only once, as long as no additional radioactive liquids have been added. .The. liquid level' in all these tanks is recorded and high level annunciated. .In-addition, floor drain sample ' tanks 'and Haste sample tanks are-batch-emptied so that as one tank is being discharged ~ the other may be filled. Therefore, both tanks of a type could not normally. be expected to be tilled at the same time. The Haste surge ; tank - ~ is used as backup storage capacity during maintenance on other: tanks or to accommodate other unusual conditions.
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The reactor Hater sample Hill be used to assure that the limit of? Specification 3.6.D is not exceeded. The total radioactive iodine l (
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activity would not be expected to change rapidly over a period of several days. In addition, the trend of the stack off-gas release rate. Which is continuously conitored, is a good indicator of the trend of the iodine activity in the reactor coolant. Refercnce (1) FDSAR, Volume I, Sections VII-6-2-3 and VII-6-2-5. n \ l i l l 4.6-5 l l-
4.7 AUXILIARY ELECTRICAL POUER Applicability: Applies to surveillance requirements of the cuxiliary electrical supply. Obiective: To verify the availability of the auxiliary electrical supply. Specification: A. Diesel Generator
- 1. Each diesel generator shall be started and loaded to not-less than 20% rated power every tHo Heeks.
- 2. The tHo diesel generators shall be automatically actuated and functionally tested during each refueling outage. This shall-include testing of the diesel generator load sequence timers listed in Table 3.1.1.
- 3. Each diesel generator shall be given a thorough-inspection at least once per 10 months during shutdown.
- 4. The diesel generators'- fuel supply shall be checked following the above tests.
- 5. The diesel generators' starting batteries shall be tested and monitored the same as the station batteries, Specification 4.7.B.
B. Station Batteries
- 1. Weekly surveillance Hill be performed to verify the.
folloHing:
- a. The active metallic surface of the plates shall be fully covered with electrolyte in.all batteries,
- b. The designated pilot cell voltage is greater than or equal to 2.0 volts and'
- c. The overall battery . Voltage; is . greater than or-equal to 120 volts (Diesel battery; 112 volts).-
- d. The pilot ec11 specific gravity, corrected to 77'F, is greater than or. equal to.1.190., .
- 2. Quarterly Surveillance Hill be performed to verify the:
following:
- a. The active metallic' surface of the plates shall be fully covered Hith electrolyte in all batteries,-
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- b. The voltage of each connected cell is greater than or equal to 2.0 volts under float charge and
- c. The specific gravity, for each cell, is greater than or equal to 1.190 when corrected to 77"F. The electrolyte temperature of every fifth cell (Diesel; every fourth cell) shall be recorded for surveillance revicH.
- 3. At least once per 18 months during shutdown, the following tests Hill be performed to verify battery capacity.
- a. Battery capacity shall be demonstrated to be at least 80% of the manufacturers' rating when subjected to a battery capacity discharge test.
- b. Battery low voltage annunicators are verified to pick up at 115 volts plus or minus i volt and to reset at 125 plus or minus 1 volt (Diesel; 112 volts plus or minus 1 volt).
Bases: The biweekly tests of the diesel generatdrs are primarily to check for failures and deterioration in the system since last use. The manufacturer has recommerided the two week test interval, based on experience Hith many of their engines. One factor in determining this test interval (besides checking whether or not the engine starts and runs) is that the lubricating oil should be circulated through the engine appro):imately every two weeks. The diesels should be loaded to at least 20% of rated poHer until engine cnd generatcr temperatures have stabilized (about one hour). The minimum 20% load Hill prevent soot formation in the cylinders and injection nozzles. Operation up to an equilibrium temperature ensures that there is no over-heat problem. The tests also provide an engine and generator operating history to be compared with subsequent engine-generator test data to identify and correct any mechanical or electrical deficiency before it can result in a system failure. The test during refueling outages is more comprehensive, including procedures that are a:.ost effectively conducted at that time. These include automatic actuation and functional capability tests, to verify that the generators can start and assume load in less than 20 seconds and testing of the diesel generator load sequence timers which provide protection from a possible diesel generator overload during LOCA conditions. Thorough inspections Hill detect any signs of Hear long before failure. The manufacturer's instructions for battery care and maintenance with regard to the floating charge, the equalizing charge, and the addition of Hater Hill be folloHed. In addition, Hritten records Hill be maintained of the battery performance. Station batteries ~ Hill deteriorate with time, but precipitous failure is unlikely. The station surveillance procedures follow the recommended
- naintenance and testing practices of IEEE STD. 450 which have demonstrated, thorough experience, the ability to provide positive indications of cell deterioration tendencies long before such tendencies cause cell irregularity or improper cell performance.
4.7-2 i l l' g .
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4.8 ISOLATION CONDENSER n
,g Apolicability: -
Applies to periodic testing requirements for the isolation condenser system. Obiective: To verify the operability of the isolation condenser system. Specification: A. Surveillance of each isolation condenser loop shall be as follows: Item Frequency
- 1. Operability of motor operated Once/ month isolation valves and condensate makeup valves.
1
- 2. Automatic actuation and Each refueling functional test. outage or follow-ing major repair.
- 3. Shell side water volume check. Onec/ day
- 4. Isolation valve (steam side)
- a. Visual inspection Each refueling O- b. External leakage check outage Each primary system leak test '
- c. Area temperatures check Once/ shift Bases: Motor operated valves on- the isolation condenser steam and i condensata lines and on the condensate makeup line that are normally on standby should be exercised periodically to make sure that they are free to operate. The valves Hill be stroked full' length every time they are tested to verify proper functional performance. This fecquency of testing is- consistent With instrumentation tests discussed in Specification 4.1. . Engineering t- judgement based on experience and availability analyses of' the type presented in Appendix L of the FDSAR indicates that testing these components once a month provides assurance of availability of the system. Also, at this frequency of testing, Hearout should not be a problem throughout the life of the plant.
The automatic actuation and functional test Hill demonstrate the. automatic opening of the condensate return -line valves and the
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main steam 1ines. Automatic closura of the isolation condenser l steam' and condensate . lines on actuation of the condenser pipe l break detectors Hill also be verified by the test. . It is during a' major maintenance or repair that a system's design intent may be O 4.8-1
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violatcd cecid:ntally. This makrs th: functional t:st nec2ssary after every major repair operation. By virtue of normal plant operation the operators daily observe the Hater level in the isolation condensers. In addition, isolation condenser shell side water level sensors provide centrol room annunciation of condenser high or loH Hater level. Each refueling outage the insulation Hill be removed from the steam side isolation valve and the external valve bodies Hill be inspected for signs of deterioration. Additionally, special attention is specified for these valves during primary system Icakage tests and the temperature in the area of these valves is checked once each shift for temperature increases that would indicate valve leakage. The special attention given these valves in the design and during their construction (1) along with the indicated surveillance is judged to be adequate to assure that these valves Hill maintain their integrity when they are required for isolation of the primary containment. Reference (1) Licensing Application, Amendment 32, Cuestion 5. O l 4.8-2 O 7 - I l'
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- 4.9 REFUELING
. Applicability:
Applies to the periodic testing of. those interlocks and
- instruments used during refueling.
Obiective: To verify the operability of instrumentation and interlocks in use during refueling. i Seecification A. The refueling ' interlocks shall be tested prior to any fuel handling Hith the head off the reactor vessel, at' Heekly i intervals thereafter .until no longer required and following i any repair Hork associated Hith the interlocks.
, B. Prior to beginning any core alterations, the source range monitors (SRMs).shall be calibrated. Thereafter, the SRM's Hill be checked daily, tested monthly and calibrated every 3 months until no. longer required.
i- C. Within four (4) hours price- to the start of control rod removal pursuant to Specification 3.9.E_ verify:
- 1. That the reactor mode sHitCh is locked in the refuci.
position and that the one' rod out refueling interlock Lis operable. , 2. That two (2) SRM channels, one in-the core-quadrant Hhere the Control rod is being removed and one in an adjacent quadrant, are operable and inserted to the normal operation level. i D. Verify within fcu- (4) hours prior to the start of control rod removal pursuant to Specification 3.9.F' and at least.once per 24 hours therafter, until replacement of all controrrods
, or rod drive mechanisms and all control rods are fully inserted that:
- 1. 'the reactor mode switch is locked'in the refuel position-and the one rod out refueling. interlock is operable.
} 2. THo (2)~ .SRM channels, one in the core quadrant Hhere a. !- control rod is being removed and one in an adjacent quadrant,
.are operable and fullyJinserted.
All control rods not removed are fully inserted Nith the
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3. exception of one rod which may be' partially ~N ithdrawn not' more than' tNo notches toi perform refueling ~ interlock-
-surveillance.
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- 4. The four fu:1 essembliss surrounding cach control rod er rod drive mechanism being removed or maintained at the same time are removed from the core cell.
E. Verify prior to the start of removal of centrol rods pursuant to Specification 3.9.F that Specification 3.9.F.5 will be met. F. Following replacement of a control rod or rod drive mechanism removed in accordance with Specification 3.9.F, prior to inserting fuel in the control cell, verify that the bypassed refueling interlocks associated with that rod have been removed and that the control rod is fully inserted. Bases: The refueling interlocks (1) are required only when fuel is being handled and the head is off the reactor _ vessel. A test of these interlocks price to the time when they are needed is sufficient to ensure that the interlocks are operable. The testing frequency for the refueling interlocks is based upon engineering judgement and the fact that the refueling interlocks are a backup for refueling procedures. The SRM's (2) provide neutron monitoring capability during core alterations. A calibration using external testing equipment to calibrate the signal conditioning equipment price to use is sufficient to ensure operability. The frequencies of testing using internally generated test signals, and recalibration, if the SRM's are required for an extended period. of time, are in agreement with other instruments of this type Hhich are presented in Specification 4.1. , The surveillance requirements for control rod removal assure that the requirements of Specification 3.9 are met prior to initiating control rod removal and at appropriate intervals thereafter.
References:
(1) FDSAR, Volume I, Section VII-7-2.5. (2) FDSAR, Volume I, Sections VII-4.2.2 and VII-4-5.1. t i
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1 l 1 1 4.10 ECCS RELATED CORE LIMITS j O V. Applicability: Applies to the periodic measurement during power operation of core parameters related to ECCS performance. Obiective: To assure that the limits of Section 3.10 are not being violated. Scecification: - A. Averace Planar LHGR The APLHGR for each- type of fuel as a function of average planar exposure shall be checked daily during reactor operation at greater than or equal to 25% rated thermal power. B. Local LHGR The LHGR as a function of core height shall be checked daily during reactor operation at greater than or equal to 25% rated thermal power. C. Assembiv Avernoed Power-Void Relationship (Applicable to Fuel Type IIIF for 4-Loop Operation Only) (Os/ Co=pliance with the Power-Void Relationship in Section 3.10 uill be verified at least once during a startup between 50% and 70% power, when steady state power operation is attained and at least every 72 hours thereafter during power operation. D. Miniw1m Critical Power Ratio (MCPR) . 1 MCPR and APRM status shall be checked daily during reactor operation at greater than or' equal- to 25% rated. thermal-pouer. , Bases: The LHGR shall be checked daily to determine whether fuel burnup or control rod movement has caused changes in power ~ distribution. Since changes due to burnup are slow, and only a'few control rods y are moved daily, a daily check of poHer distribution is adequate. l The Power-Void Relationship is verified between 50% and 70% power: during a startup. -This single verification during startup is acceptable since operating . experience has shown that even under ' the most ~ extreme void conditions -encountered 1 at. lower power-levels, the relationship is not violated. Additionally reduced power operation involves less stored heat in the core and loHer decay heat rates Hhich Hould add further. margin to limiting peak. " clad temperatures.in the event of a LOCA. t 4.10 ! s
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V;rification wh:n steady stata power operation is tttain;d and every 72 hours thereafter is appropriate since once steady state conditions are achieved, the void fraction, radial peaking factor, and power 1cvc1 that combine to form the relationship are unlikely to change so rapidly to result in a significant change during that period. The minimum critical power ratio (MCPR) is unlikely to change l significantly during steady state powcr operation so that 24 hours is an acceptable frequency for surveillance. In the event of a single pump trip, 24 hour surveillance interval remains acceptabic because the accompanying power reduction is much larger than the change in MAPLHGR limits for four loop operation at the corresponding lower steady state power icvel as compared to five loop operation. The 24 hour frequency is also acceptable for the APRM status check since neutron monitoring system failures are infrequent and a downscale failure of either an APRM or LPRM initiates a control rod withdrawal block thus precluding the possibility of a control rod withdrawal crror. At core power icvels less than or equal to 25% rated thermal power the reactor will be operating at or above the minimum recirculation pump speed. For all designated control rod patterns which may be employed at this point, operating plant experience and thermal hydraulic analysis indicate that the resulting APLHGR, LHGR and MCPR values all have considerabic margin to the limits of section 3.10. Consequently, monitoring of these quantitics below j 25% of rated thermal power is not required. O l
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4.11 SEALED SOURCE CONTAMINATION
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s- - Applies to each licensed sealed source containing radioactive material either in excess of 100 microcuries of beta and/or gamma emitting materials cr 5 microcuries of alpha emitting material. Obiective: To detect and prevent contamination from sealed source leakage. Specification: A. Radioactive sources shall be tested for contamination. The test shall be capable of detecting the presence of 0.005 microcurie of radioactive material on the test sample. If the test reveals the presence of 0.005 microcurie or more of removeable contamination, it shall immediately be withdrawn from use, decontaminated, and repaired, or be disposed of in accordance with Commission regulations. B. Tests for contamination shall be performed by the licensee or by other persons specifically authorized by the Commission or an agreement state as follows:
- 1. Each sealed source, except startup sourecs previcusly subjected to core flux, containing radioactive material, other than Hydrogen 3, with a half life greater than thirty Os days and in any form other than gas shall be tested for contamination at intervals not to exceed six months.
- 2. The periodic leak test required does not apply to sealed sources that are stored and not being used. The sources excepted from this test shall be' tested prior to any use or-transfer to another user unless they have been tested within-six months prior to the date of use or transfer. In the absence of a certificate from a transfer or indicating that a test has been made within six months prior to the transfer, sealed sources shall not be put into use until' tested.
- 3. Startup sources shall be tested prior to and following any repair or modification and within 31 days before being subjected to core flux.
Bases: Ingestion or inhalation of source material may give rise to total body or organ irradiation. This- specification assures' that-leakage from . radioactive material sources does not exceed
- allowable limits. .
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4.12 FIRE PROTECTION Applienbility: Applies to the surveillance requirements of the Fire Protection Systems in safety related areas /mones. Obiective: To specify the minimum frequency and type of surveillance to be applied to fire protection equipment and instrumentation. Specifications: A. Fire Detection Instrumentation
- 1. Each of the instruments in Table 3.12.1 shall be demonstrated operable by a channel function test at least once per 6 months.
- 2. The NFPA Code 72D(1977) Class A supervised circuits supervision associated with the detector alarms of each of the above required fire detection instruments shall be demonstrated operable at least once per 6 months.
B. Fire Superession Unter Svsten
- 1. The Fire Suppression Water System shall be demonstrated operable:
- a. At least once per conth on a staggered test basis by starting each pump and operating it for at least (15) minutes on recirculation flou.
- b. At least once per centh by verifying that each valve in the flow path is in its' correct position.
- c. At least once per 12 months by performance of a system flush.
- d. At least once per 12 months by cycling each testable valve in the flow path through at least one complete cycle of full travel.
- e. At least once per 18 months by performing a system functional test which includes simulated automatic actuation of the system throughout its operating sequence, and:
- 1. Verifying that. each pump develops at least 2000 gpm at a system head of 360 feet.
- 2. Verifying that the pump operates for greater than or equal to 60 minutes.
4.12-1 O
- 3. VIrifying that etch high prassure pump starts sequentially to maintain the fire suppression water system pressure at 125 psig or greater.
- f. At least once per 3 years by performing a flow test of the system in accordance with Chapter 5, Section 11 of the Fire Protection Handbook, 14th Edition published by the National Fire Protection Association. ,
1
- 2. The Fire Pump Diesel Engine shall be demonstrated operable.
- a. At least once per month by verifying the fuel storage tank contains at least 275 gallons of fuel.
-b. At least once per month by verifying that the diesel starts from ambient conditions and operates for at least 30 minutes on a circulation flow,
- c. At least once per 3 months by verifying that a fuel sample, obtained in accordance with ASTM-0270-65, from each tank is within the acceptable limits specified in Table 1 of ASTM D 975-1974 when checked for -viscosity, water and sedimqnt.
- 3. The Fire Pump Diesel 24 volt battery bank and associated charger shall be demonstrated operable:
- a. At least once per week by verifying that:
,Q (1) The electrolyte level of each cell is above
() the plates, . (2) The pilot cell voltage is greater than or equal to 2.0 volts, (3) The pilot cell specific gravity, corrected to 77 8 F, will be recorded for surveillance review. (4) The overall battery voltage is greater than or equal to 24 volts.
- b. At least once per 3 months by verifying that:
(1) The voltage of each connected cell is greater than or equal to 2.0 volts. (2) The specific gravity, corrected to 77 8F, of each cell-will be recorded for surveillance review. ^ (3) The electrolyte level of each cell is above ' the plates.
- c. .At least once per 18 months by verifying that:
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(1) The batterias, cell plates and battery ricks show no visual indication of physical damage or abnormal deterioration, and (2) The battery-to-battery and terminal connections are clean, tight, free of corrosion and coated Hith an anti-corrosion material. C. Serav and/cr Sprinkler Systems
- 1. The spray and/or sprinkler systems listed in Table 3.12.2 shall be demonstrated operable' at least once per 18 months:
- a. By performing a system functional test which includes simulated automatic actuation of the system and verifying that the automatic valves in the flow path actuate to their correct positions.
- b. By inspection of the Hater headers to verify their integrity.
- c. By inspection of each open spray noz=le to verify no blockage.
D. Hose Stations
- 1. Each of the hose stations listed in Table 3.12.3 chall be verified operable:
- a. At least once per month by visual inspection of the station to assure all equipment is available.
- b. At least once per 18 months by removing the hose for inspection and reracking and replacing all gaskets in the couplings that are degraded.
- c. At least once per 3 years by:
(1) Partially opening each hose station valve to verify valve operability and no flow blockage. (2) Conddcting a hose hydrostatic test at a pressure at least 50 psig greater than the maximum pressure available at that hose station. E. Penetration Fire Barrier
- 1. Each penetration fire barrier in fire area boundaries shall be verified to be functional by a visual inspection:
- a. At least once per 18 months, and
- b. Prior to declaring a penetration fire barrier functional following repairs or maintenance.
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- 1. Tha CO2- system .for the 4160 volt emergency switchgear vault shall be demonstrated operable:
- a. At least once per week by verifying that the O storage tank level is. greater than or equal to 1/2 full and the pressure is at least 275 psig.
b.. At least once per month by verifying that each manual valve in the flow path is in its correct position.
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- c. At least once per 18 months by verifying that:
(1) The system valves and associated ventilation dampers actuate automatically upon receipt of a simulated actuation signal, and (2) Flow is observed from each nozzle during a
" puff test".
G. Halon Systems
- 1. Each of the Halon Systems listed in Table 3.12.4 shall be demonstrated operable:
- a. At least once per 6 months by verifying Halon ,
storage tank weight or level and pressure.
- b. At least once per 18 months by:
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(1) . Verifying the system, including associated ventilation dampers, actuate manually and automatically, upon receipt of a simulated test signal. (2) Performance of a flow test through headers and nozzles to assure no blockage. H. Yard Fire Hydrants and Hydrant Hose Houses
- 1. Each of the yard fire hydrants and associated hydrant- .
hose houses shown in Table. 3.12.5 shall be demonstrated-operable:
.a. At least once per 31' days by visual inspection of-the hydrant hose house to assure all required . equipment is at the hose house.
- b. -At least >once per 6 monthsT(once~during March,; -
April, or May and once during~-September,. October. or. November) by visually inspecting each yard fire hydrant- ~ and verifying that the hydrant barrel is' dryLand 'that. the hydrant is not damaged. ' - A
- c. At least once per 12 months by:
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(1) Conducting c hose hydrostatic trst and a pressure at least 50 psig greater than the maximum pressure availabic at any yard fire hydrant. (2) Inspecting all the gaskets and replacing any degraded gaskets in the couplings. (3) Performing a flow check of each hydront to verify :.'e operability. Bases: Fire Protection systems are normally inactive and require periodic examination and testing to assure their readiness to respond to a fire situation. These specifications detail inspections and tests which Hill demonstrate that this equipment is capable of performing its intended function. O 4.12-5
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4.13 ACCIDEf!T !!O!!ITO' tit!O It!STRUME!!TATION Applicebility: Applies to surveillance requirements for the accident monitoring instrumentation. Obiective: To verify the operability of the accident monitoring instrumentation. Specification: A. Safety & Relief Velve Position Indicators Each accident monitoring instrumentatiori channsi shall be demonstrated operable by performance of the Channci Check and Channel Calibration operations at the frequencies shown in Table 4.13.1. Bases: The operability of the accident monitoring instrumentation ensures that sufficient information is available on selected plant paramenters to monitor and assess these varicbles during and follo: ling an accident. This capability is consistent Hith IIUREG 0570. h e
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SECTION 5 DESIGN FEATURES 5.1 SITE A. The reactor (center line) is located 1,358 feet west of.the_ .. _ east boundary of New Jersey State Highway Route 9 which is the minimum exclusion distance as defined in 10 CFR 100.3. No part of the property which is closer to the reactor (center line) than 1,358 feet shall be sold or leased. B. The reactor building, standby gas treatment system and stack shall comprise a secondary containment in order to provide for controlled elevated release of the reactor building atmosphere under accident conditions. 5.2 CONTAINMENT
/
A. The primary containment shall be of the pressure suppression type having a drywell and an absorption chamber constructed of steel. The drywell shall have a volume of approximately 180,000 cubic feet and is designed to conform to ASME Boiler and Pressure Vessel Code Section VIII for an internal pressure of 62 psig at 175"F and an external prcssure of 2 psig at 150"F to 205"F. The absorption chamber shall have a total volume of approximately 210,0C0 cubic feet. It is designed to conform to ASME Boiler and Pressure Vessel Code Section VIII for an internal pressure of 35 psig at 150"F and O an external pressure of-1 psig at-150"F. B. Penetrations added to the primary containment shall be designed in accordance with standards set forth in Section V-1.5 of the Facility Description and Safety Analysis Report. Piping passing through such penetrations shall have isolition valves in accordance with standards set forth in Section V-1.6 of the Facility Description and safety Analysis Report. 5.3 AUXILIARY EQUIPMENT 5.3.1 Fuel Storage A. Normal storage for unirradiated fuel assemblies 'is - in . critically safe new fuel. stor8ge racks in the .Peactor building storage vault; otherwise, fuel shall be stored in arrays which have a Xeff less than 0.95 .under optimum conditions of' moderation or in NRC-approved. shipping containers. B. The spent fuel shall be stored in the' spent fuel storage ' facility which shall be designed to maintain ! fuel ~ in a geometry providing a k infinity-less than or squal to 0.95. C. The maximum U-235 loading in grams of--U-235 per axial ~
-centimeter of fuel shall not exceed 15.6 gas U-235/ca.
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D. Loads gent:r th n th7 w;ight of en2 fu21 tss;mbly shall not be moved over stored irradiated fuel in the spent fuel storage facility. E. Thc 30 ton spent fuel shipping cask shall not be lif ted morc than 6 inches above the top piste of the cask drep protection system. Vertical limit switches shall be operable to assure the 6 inch vertical limit'is met uhen the cask is above the top plate. F. The temperature of the Hater in the spent fuel storage pool, measured at or near the surface, shall not exceed 125'F. Bases: The specification of X inifinity less than or equal to 0.95 and the maximum U-235 leading of less than or equal to 15.6 go U-235/cm per axial centimeter for fuel in the spent fuel storage facility assures an ample margin from criticality. Conservative assumptions and allowance for tolcrance, void effects, calculational uncertainties, pool temperature effcets, etc. have been considered in the derivation of these limits (1,2). Note that the 15.6 gm U-235/cm is equivalent to a 3 H/o enrichment.(7) The 15.6 gm U-235/cm is the limit of U-235 at any plane through the assembly perpendiculer to the length of the assembly. It is to assure that possible non-uniform enrichments along the length of fuel rods cannot lead to a critical condition. The effects of a dropped fuel bundle onto stored fuel in the spent fuel storage facility has been analy:cd. This analysis shows that the fuel bundle drop would not cause doses resulting from ruptured fuel pins that execed 10 CFR 100 limits (3,4,5) and that dropped Haste cans Hill not damage the pool lincr. The elevation limit of the spent fuel shipping cask to no more than 6 inches above the top plate of the cask drop protection system prevents loss of the pool integrity resulting from postulated drop accidents. An analysis of the effccts of a 100 ton cask drop from 6 inches has been done (6) which showed that the pool structure is capabic of sustaining the loads imposed during such a drop. Limit switches on the crane restrict the elevation of the cask to less than or equal to 6 inches when it is above the top plate. Detailed structural analysis of the spent fuel pool was performed using loads resulting from the dead weight of the structural elements, the building loads, hydrostatic loads from the pool watcr, the Height of fuel and racks stored in the pool, seismic loads, loads due to thermal drop accident. Thermal gradients result in two loading conditions; normal operating and the accident conditions Hith the loss of spent fuel pool cooling. For the normal condition the containment air temperature was assumed - to vary between 65'F and 110"F Nhile the pool Hatcr temperature varied between 85'F and 125"P. The most severe loading from the normal operating thermal gradient results with containment air temperature at 65'T and the water temperature at 125'F. Air temperature measurements made during all phases of plent operation in the shutdown heat exchanger room, which is directly beneath 5.1-2 9
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i i part of the spent fuel pool floor slab, shoH that 65'F is the , appropriate minimum air temperature. The spent fuel pool Hater l temperature Hill alarm in the control room before the water . temperature reaches 120'F. 1 i Results of the structural analysis shoH that the pool structure is structurally adequate for the loadings associated .'ith the normal . operation and the condition resulting from the postulated cask l~ drop accident (9). The fuel pool floor framing Has found to be capable of Hithstanding the maximum postulated thermal transient for at least 15 hours Hithout exceeding ACI Code requirements. ' j The floor framing was also found to be capable of Hithstanding the i steady state thermal gradient ' conditions with the pool Hater ' temperature at 150'F 'Without. exceeding ACI Code requirements. i Studies shoH that the critical elements of the Halls indCntified l in the analyses of (8) are capable of Mithstanding eight hours of
- the maximum postulated thermal transient Hithout. exceeding ACI Code requirements and they are judged.able to continue full.
1 i . functional capability for at least.10 hours under these conditions (9). The Halls are also capable of operation at a steady state condition Hith the pool Water temperature at 140'F (9). 7 { . Since the cooled fuel pool Water returns to the pool at the bottom of the pool and the heated Hater is removed from the surface of . the pool, tc=perature measurement at the pool surface is [ appropriate to estimate the pool bulk temperature. l References (1) Amendment 78 to the Facility Description and i
! Safety Analysis Report (Section 3) ,
4 (2) Supplement:1 to Amendment No. 78 to the Facility ~ Description and Safety Analysis Report
-(Questions'14-20,f24, 25)
(3) Amendment 78 to the FDSAR (Section 7) } (4). Supplement No. 1 to Amendment,78 to the FDSAR (Question 12)I (5) . Supplement No.(1 to Amendment 78 of the.FDSAR (Question 40) , (6) , , Supplement.:NoJ1'.toAmindsent68(cftheFDSAR
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.(7) Supplement No. 1 to Amendment 78 of the FDSAR (Question'18). !
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- of the FDSAR-(Question 5 and 10).
. (9) Revision No.K 1 to Addendum.2 to Supplement No. i'to- ..
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Section 6 I ADMIllISTRATIVE CONTROLS l 6.1 RESPCNSIBILTY_ 6.1.1 The Vice President & Director shall be responsible for overall facility operation. Those responsibilites delegated to the Vice President & Director as stated in the Oyster Creek Technical Specifications may also be fulfilled by the Deputy Director. The Vice President & Director shall delegate in writing the succession to this responsibility during his and/or the Deputy Directors absence. 6.2 GRGANI2ATION 6.2.1 OFFSITE The organization for GPU Nuclear Corporation for management and technical support shall be functionally as shown on Figure 6.2.1. 6.2.2 FACILITY STAFF The facility organi=ation shall be as shown on Figure 6.2.2 and:
- a. Each on duty shift shall include at least the shift staffing indicated on Figure 6.2.2.
- b. At least one licensed reactor operator shall be in the control room O- when fuel is in the reactor.
- c. Two licensed reactor operators shall be in the control room during all reactor startups, shutdowns, and other periods involving planned control rod manipulations,
- d. ALL CORE ALTERATIONS shall be directly supervised by either a licensed Senior Reactor Operator or Senior Operator Limited to Fuel Handling who has no other concurrent responsibilities during this operation.
- e. An individual qualified in radiation protection measures shall be on site when fuel is in the reactor.
- f. A Fi:'e Brigade of at least 5 members shall be maintained onsite at all times. The Fire Brigade shall not include the minimum shift crew necessary for safe shutdown of the unit or any personnel required for other essential functions during a fire emergency.
- g. Each on duty shift shall include a Shift Technical Advisor except .
that the Shift Technical Advisors position need not be filled if the reactor is in the refuel or shutdown mode and the reactor is less than 212*F. 6.1-1 c y .
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6.3 FACILITY STAFF CUAT,IFICATIONS 6.3.1 The members of the facility staff shall meet or exceed the following qualifications: Vice President & Director / Deputy Director Requirements: Ten years total power plant experience of which three years must be nuclear power plant experience. A maximum of four years of acadcric training may fulfill four of the remaining seven years of required experience. Both must be capabic of obtaining or possess a Senior Reactor Operator's License. Plant Operations Director Requirements: Eight years total power plant experience of which three years east be nuclear power plant experience. A maximum of two years of academic or related technical training may fulfill tuo years of the remaining five years of required experience. The Plant Operations Director must be capable of obtaining or possess a Senior Reactor Operators's License. Plant Engineering Director Requirements: Eight years of responsible positions related to poner generation, of which three' years shall be nuclear power plant experience. A maximum of four of the remaining five years of experience may be fulfilled by satisfactory completion of academic ce related technical training. M nacer Plant Administration Requirements: Eight years total power plant experience of which four years mu::t have been in nuclear power plant experience. The Manager should possess a four year college degree or equivalent in Business Administration or an Engineering discipline. Manager Plant Operations Requirements: Eight years total power plant experience of which three years must be nuclear power plant experience. A maximum of two years of academic or reinted technical training may fulfill two of the remaining five years of required experience. The Manager Plant Operations must possess a Senior Reactor Operator's License. Safetu Revieu Manacer Requirements: Eight years total power plant experience of Hhich three years must be nuclear power plant experience. A maximum of two years of academic or related technical training may fulfill tuo of the - remaining five years of required experience. 6.1-2 I l- l'
Honocer Core Encineerinq At the time of initial core loading or appointment to the position, whichever is later, the responsible- person shall have a Bachelor's Degree in Engineering or the Physical Sciences. and four years experience or a graduate. degree and three years experience. Two of these years shall be nuclear power plant experience. The experience shall be in such areas as reactor physics, core measurements, core heat transfer, and core physics testing programs. Successful completion of a reactor engineering training program (such as the 12 _.Week concentrated programs offered by NSS Vendors) may be equivalent to one-years's nuclear power plant experience. 7 Hanacer Plant Materiel Requirements: Seven years of total power plant experience of which one year must be nuclear power plant experience. Two years of academic or related technical training may fulfill two of the remaining six years-of required experience. Area Supervisor Instrument & Computer Maintenance Requirements: Five years of experience in instrumentation and control,' of which a minimum of one year shall be in nuclear instrumentation and control at an operating nuclear power plant. A maximum of four years , cf this five year experience may be fulfilled by related technical or academic training. Hanecer Plant Encincerinq
)
The engineer in charge of technical supportishall have a Bachelor's-Degree in Engineering or the Physical Sciences and have three years of professional level experience in nuclear services, . nuclear plant operation, or nuclear. engineering, and the = necessary .overall nuclear. background to determine. when to call consultants and contractors forc dealing Hith Complex problems beyond the Lscope of oHner-organization. expertise. , Mannaer/ Deputy Radioloaical Controls (Recorts Offsite) Requirements: . Bachelor's l degree or the -equivalent in a science or, engineering subject, including some formal training. in radiation-
-protection. Five years of professional experience in applied radiation protection. (Master's degree equivalent to: one ' year experience and Doctor's degree equivalent to two years experience where coursework' related to radiation protection.is involved.) Three years of this professional experience should be in applied radiation protection work 1 in a nuclear facility dealing with radiological- problems Esimilar to -
those encountered in nuclear power. stations..
~ Chemistry Manaaer .
6 Requirements: Five years experienceLin chemistry of which a minimum ofC one year shall be in radiochemistry at an operating nuclear poHer
- plant. A maximum of four years of this five year experience may.be' L fulfilled by related technical or academic. training.- ~ .,;
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M&C Director. O.C l Requirements: Seven years of total power plant experience of which one year must be nuclear power plant experience. Two years of academic or related technical training may fulfill two of the remaining six years of required experience. Shift Technical Advisor _ J Requirements: Bachelor's degree or equivalent in a scientific cr engineering discipline with specific training in plant design, and response and analysis of the plant for transients and accidents. 6.3.2 Each member of the radiation protection crganimation for which there is a comparable position described in ANSI H18.1-1971 shall meet or exceed the minimum qualifications specified therein, or in the case of radiation protection technicians, they shall have at leat one year's continuous experience in applied radiation protection ucrk in a nuclear facility dealing with radiological problems similar to those encountered in nuclear power stations, and shall have been certified by the Manager / Deputy Radiological Controls, as qualified to perform assigned functions. This certification must be based on an HRC approved, documented program consisting of classroom training with appropriate examinations and documented positive findings by responsible supervision that the individual has demonstrated his ability to perform each specified procedure and assigned function with an understanding of its basis and purpose. 6.4 TRAINING 6.4.1 A retraining program for operators shall be maintained under the direction of the Manager Plant Training Oyster Creek and shall meet the requirement _s and recommendation of Appendix A of 10CFR Part 55. Replacement training programs, the content of which shall meet the requirements of 10CFR Part 55, shall be conducted under the direction of the Manager Plant Training Oyster Creek for licensed operators and Senior Reactor Operators. 6.4.2 A training program for the Fire Brigade shall be maintained under the direction of the Manager Plant Training Oyster Creek. 6.5 SAFETY REVIEW AND AUDIT The Vice President & Director and three organizational units, the P1 9t Operations Review Committe (PORC), the Independent Safety Review Groups (ISRG) and the General Office Review Board (GORB) function to - accomplish nuclear safety review and audit of the Oyster Creek Station. 6.1-4
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6.5.1 VICE PRESIDENT C DIRECTOR 6.5.1.1 FUNCTION
) The Vice President & Director shall ensure that: %J
- a. All proposed changes to equipment or systems have been evaluated to determine if they constitute a change to the facility or procedures as described in the Safety Analysis Report. -
- b. All proposed changes to equipment or systems that constitute a change of the facility or procedures as described in the Safety Analysis Report have been evaluated to determine whether they involve an unreviewed safety question as defined in paragraph 50.59, Part 50, Title 10, Code of Federal Regulations.
- c. All proposed tests and experiments have been evaluated to determine whether or not they involve unreviewed safety questions as defined in paragraph 50.59, Part 50, Title 10, Ccde of Federal Regulations.
6.5.1.2 AUTHORITY The Vice President & Director has the authority to:
- a. Make a determination as to whether proposed changes to equipment, or systems involve a change to the procedures or facility as described in the Safety Analysis Report.
- b. Make a determination as to whether or not proposed tests or experiments and changes to equipment or systems involve on unreviewed safety question.
- c. Direct the Plant Operations Review Committee to review safety evolutions of proposed changes to equipment or systems and safety evaluations of proposed tests and experiments to determine whether or not such changes, tests or experiments involve unreviewed safety questions.
NOTE: Each determination that a proposed . test, experiment, or change to a system or equipment that does not involve an unrevieHed safety question shall be reviewed by the Independent Safety.RevieH Groups to verify that the determination was correct. This review shall be documented but is not a pre-requisite of the test, experiment, or change to a system or equipment. 6.5.1.3 RECORDS
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Any safety evaluations done in accordance with 6.5.1.1 (b) and (c) and any determinations made pursuant to 6.5.1.3.(b)- must be documented. Copies of these determinations shall be provided to the ISRG Coordinator and the Chairman of the General Office Review Board.
-Records of all tests and experiments performed and all changes to.. -
equipment or systems made under the provisions of 10_ CFR Part 50.59 shall also be maintained at the station. v 6.1-5
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6.5.2 PLANT OPERATIONS REVIE!! COMt!ITTEE (PORC) 6.S.2.1 FUNCTION The PORC shall function to advise the Vice President & Director. 6.5.2.2 COMPOSITION The PCRC shall consist of the following plant personnel: Safety Revicu Manager Plant Operations Director Plant Engineering Director Manager Plant Materiel Manager / Deputy Radiological Controls.
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The Vice President & Director shall designate the Chairman and Vice-Chairman from among the PORC members. 6.5.2.3 ALTERNATES Alternate members shall be appointed in writing by the PORC Chairman and will have the type of experience and training required of regular members. However, they need not have the extensive lengevity in the designated fields as long as in the opinion of the Chairman, their experience and judgement are adequate. 6.5.2.4 MEETING FREQUENCY The PORC shall meet at least once per calendar month as convened by the PORC Chaim an or the Vice President & Director. 6.5.2.5 OUORUM A quorum of the PORC shall consist of the Chairman or Vice Chairman and three_ members / alternates. No more than tHo alternate members shall be countcd in establishing a quorum. 6.5.2.6 RESPONSIBILITIES l The responsibilities of the PORC are included in Table 6.5.1. 6.5.2.7 AUTHORITY l l
- a. The PORC shall be advisory to the Vice President & Director.
Nothing herein shall relieve the Vice President & Director of his responsibility or authority for overall safety operations including taking immediate emergency action. Determinations on Items a and b of Table 6.5.1 shall be documented in writing. 6.5.2.8 RECORDS The PORC shall maintain written minutes of each meeting and copies of minutes and determinations shall be provided to the Vice President & Director, ISRG Coordinator, and the Chairman of the GORB. 6.1-6 I l'
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6.5.3 INDEPEMDENT SAFETY REVIEH GROUPS (ISRG) 6.5.3.1 FUNCTICM AND COMPOSITION The ISRG shall function under the direction of an ISRG Coordinator, who shall be appointed by the Vice President & Director to provide safety reviews. The ISRG Coordinator shall have available the competence to revien probicos in the following area:
- a. Nuclear Power Plant Operations
- b. Nuclear Engineering
- c. Chemistry and Radiochemistry
- d. Metallurgy
- e. Instrumentation and Control
- f. Radiological Safety
- g. Mechanical and Electrical Engineering
- h. Quality Assurance practices The Coordinater shall establish, as needed, groups of tuo or more individuals with the expertise required for each topic to be reviewed.
6.5.3.2 CONSULTANTS Consultants shall be utili=ed as necessary to supplement the expertise available in the GPU Nuclear Corporation. 6.5.3.3 RESPCMSIBILITIES The specific responsibility to ensure accomplishment of the independent safety review of the Vice President & Director determinations involving safety questions is assigned to the ISRG Coordinator and is O. - accomplished by utilizing, as necescry, the full scope of expertise availabic in the GPU Huclear Corporation staff, consultants, contracters and vendors as appropriate. Table 6.5.1 defines the specific independent safety review responsibilities. 6.5.3.4 AUTHORITY The ISRG advises the Vice President & Director. It has the authority to conduct reviews and investigations, which Hill be documented. 6.5.3.5 AUDITS Audits of facility activities shall be performed under the cognizance of the Vice President Huclear Assurance. These audits shall encompass:
- a. The conformance of facility operation to all provisions contained within the Technical Specifications and applicable license conditions at least once per year.
- b. The performance training and qualifications of the entire facility staff at least once per year. -
- c. The results of all actions taken to correct deficiences occurring in facility equipment, structures, systems or method of operation that offect nuclear safety at least once per six months.
6.1-7 7 I l' .-
- d. The Facility Emergency Plan and implementing procedures every 12 months.
- c. The Facility Security Plan and implementing procedures every 12 months.
- f. Any area of facility operation considered appropriate by the GCRB er the Vice President & Director.
6.5.3.6 RECORDS Mritten documentation of all independent safety reviews and investigations Hill be forwarded to the Vice President & Director and the Chairman of the General Office RevicH Board. In addition, any reportabic occurrance or item involving an unreviewed safety question which is identified by the ISRG Hill be documented and reported immediately to the above mentioned persons. The audit findings which result from all audits conducted in accordance with Section 6.5.3.5 shall be documented and reported to the above mentioned persons Hithin 30 days after completing the audit. Reports documenting corrective action Hill receive the same distribution and they Hill also be forwarded to the ISRG Coordinator. 6.5.4 GENERAL OFFICE REVIEH BOARD (GORB) 6.5.4.1 FUNCTICN The technical and administrative function of the GORB is to provide independent review of major safety issues, to foresee potentially significant nuclear and radiation safety problems, and to advise the Office of the President on these matters. 6.5.4.2 COMPOSITION Members of the General Office Review Board shall possess extensive experience in their individual specialties and collectively have the competence in the following areas:
- a. Nuclear Power Plant Operations
- b. Nuclear Engineering
- c. Chemistry and Radiochemistry
- d. Metallurgy
- e. Instrumentation and Control
- f. Radiological Safety
- g. Mechanical and Electrical Engineering The Chairman and Vice Chairman shall be appointed by the Office of the President. (Neither shall be an individual with line responsibility for operation of the plant).
The Chairman shall designate a minimum of six additional members. No more than a minority of the Board shall have line responsibility for operation of Oyster Creek Nuclear Generating Station. 6.1-8
- . I l'
6.5.4.3. ALTERNATES Alternate members shall be appointed in writing by the GORB Chairman gg and Hill have the type of experience and training required of regular members, however, they need not have the extensive longevity in the designated fields as long as, in the opinion of the Chairman, their experience and judgement are adequate. 6.5.4.4 NEETIt!G FREQUENCY The GORB shall meet at least semi-annually and any time at the request of the Chairman or the Office of the President. 6.5.4.5 QUORUM A quorum shall consist of the Chairman or Vice Chairman and three members / alternates. No more than one alternate member shall be counted Hhen establishing a quorum and no more than a minority of the quorum shall hold line responsibility for operations of the Oyster Creek Station. .. 6.5.4.6 RESPONSIBILITIES
- a. The primary ' responsibility of the GORB is to foresee potentially significant nuclear and radiation safety problems and to recommend to the Office of the President hoH they may be avoided or mitigated.
- b. Carry out the specific independent safety revicu responsibilitics listed in Table 6.5.1.
6.5.4.7 AUTHORITY The GORB shall be advisory to the Office of the President and shall have the outhority to conduct revicus, audits, and investigations requrested by the Office of the President or as deemed necessary by the GORB in the fulfillment of its responsibilities. 6.5.4.8 AUDITS The report of the management revieH of the QA Plan, initiated by the-Vice President & Director in accordance Hith the Operational Quality
-Assurance Plan, shall be revieHed by the GORB Hith respect ~to safety and administrative safety issues.
6.5.4.9 RECORDS Minutes of each GORB meeting shall be recorded and approved by the GORB Chairman. Copies of approved minutes Hill be forHarded to the . Office of the President,,Vice President & Director, PORC Chairman..pr4 others designated by the GORB Chairman. GORB_ recommendations to '.Lu Ofhee of-the President Hill-be documented in a letter from the GORB Chairman to-
- the Office of the President. Included With each letteri HillbefEiny I dissenting opinions of members of the Board.
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6.6REDORTABLECCCURRENCEACTION 6.6.1 The following actions shall be t6 ken in the event of a Repertabic Occurrence:
- a. The Commission shall be notified and/or a report submitted pursuant to the requirements of Specification 6.9.
- b. Each Reportable Occurrence Report submitted to the Commission shall be reviewed by the Plant Operations Review Committee and submitted to the ISRG Coordinator and the Vice President & Director.
6.7 SAFETY LIMIT VIOLATION 6.7.1 The following actions shall be taken in the event a Safety Limit is violated:
- a. If any Safety Limit is exceeded, the reactor shall be shut down immediately until the Commission authorizes the resumption of operation,
- b. The Safety Limit violation shall be reported to the Commission and the Vice President & Director,
- c. A Safety Limit Violation Reportshallbeprepareh!. The report shall be revicHed by the Plant Operations Revicu Committee and submitted to the Vice President & Director. This report shall describe (1) applicable circumstances preceding the violation, (2) effects of the violation upon facility co=ponents systems or structures, and (3) corrective action taken to prevent recurrence.
- d. The Safety Limit Violation Report shall be submitted to the Commission Hithin 10 days of the violation. It shall also be submitted to the ISRG Coordinator.
6.8 PROCEDURES r 6.8.1 l l Hritten procedures shall be established, implemented, and maintained l that meet or exceed the requirements, of Section 5.1 and 5.3 of ' American National Standard N18.7-1976 and Appendix "A" of the Nuclear Regulatory Commission's R2gulatory Cuide 1.33-1972 except as provided in 6.8.2 and 6.8.3 below. 6.8.2 Each procedure and administrative policy of 6.8.1 above, and changes thereto, shall be reviewed by the Plant Operations Review Committee and approved by the Vice President & Director prior to imple=entation and periodically as specified in the Ad=inistrative Procedures. 6.1-10
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/ 6.8.3 Temporary changes to procedures 6.8.1 above may be made provided:
- a. The intent of the original procedure is not altered.
- b. Thechangeisapprovedbytuomemberso5thesupervisorystaff,at least one of whom possesses a Senior Reactor Operator License.
{ c. The change is documented, subsequently revieHed by the Plant
- Operations Review Committee- and approved by the Vice President & t Director as specified in the Administrative Procedures.
6.9 REPORTING REQUIREMENTS l In addition to the applicable reporting requirements of 10 CFR, the i fonowing identified reports shan be submitted to the . Director of the appropriate Regional Office of Inspection and Enforcement- unless I otherwise noted. j- 6.9.1 ROUTINE REPORTS I a. Startuo Report. 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 i design 'or has been manufactured by a different fuel supplier, and (4) mcdifications that may have significantly altered the nuclear, thermal, or hydraulic performance of the plant. The report shall address each , of the tests identified in the FSAR and shall in- general include a i description of the measured ' values of the operating conditions or
- characteristics obtained during the test' program and comparison of
- these values with design predictions and specifications. Any
! corrective actions that were required to obtain satisfactory operation a shall also be described. Any additional specified details _ required in 4 license conditions based on other commitments shan be included:in this report. . Startup reports shan ' be submitted Hithin (1) 90 days fonowing completion of the startup test program ,- (2): 90 days fononing resumption or commencement of ' commercial- power operation,:or (3) 9 months following initial criticality,.Hhichever is- earliest. If .the Startup Report does. not cover an three ' events (i.e.',. initial criticality, completion of startup test.~ program, and resumption or commencement of -commercial power' operation),- supplementary reports. 3 shan be submitted at least every three months until all -three events have been completed. b.. Annual Exposure Data Report. . ~ Routine exposure datal reports' l covering the operation of the unit during the . previous calendar year-
.shall be submitted prior to 11erch 1 'of each year. Reports shall.
contain a tabulation on an annual > basis. of- the number. of . station,. other personnel (including contractors), receiving' ter than 100_ area / year. and their. associatedi man :ren
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j ~ g, ording to work and job: functions : (this tabulation -
.he requirements .of. 10 CFR'.20.407),
e.g.. freactor-- s i surveinance, inservice inspection, routine maintenance, [
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special maint:nanca (describe mainten:nce), ursts proc;ssing, cnd refueling. The dose assignment to various duty functions may be estimates based on pocket dosimeter, TLD, or film badge measurements. Small exposures totalling less than 20% of the individual total dose need not be accounted for. In the aggregate, at -least 80% of the total whole body dose received from external sources shall be assigned to specific major work functions.
- c. Monthly Deeratino Report. Routine reports of operating statistics and shutdown experience shall be submitted on a monthly basis which will include a narrative of operating experience, to the Director, Office of Management and Program Centrol, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555, with*a copy to the Regional Office of ISE, no later than the 15th of each month following the calendar month covered by the report.
6.9.2 REPORTABLE OCCURANCES Reporting occurrences, including corrective actions and measures to prevent reoccurrences, shall be reported to the NRC. Supplemental reports may be required to fully describe final resolution of occurrance. In case of ccrrected or supplemental reports, a licensee event report shall be completed and reference shall be made to the original report date.
- a. Prompt Notification Hith Written Followuo. The types of events listed belou shall be reported as expeditiously as possible, but within l 24 hours by telephone and confirmed by telegraph, mailgram, or
! facsimile transmission to the Director of the appropriate Regional Office, or his designate no later than the first working day following the event, with a written followup report within two weeks. The written followup report shall include, as a minimum, a completed copy of a licensee event report form. Information provided on the licensee event report form shall be supplemented, as needed, by additional narrative material to provide a complete explanation of the circumstances surrounding the event. (1) Failure of the reactor protection system or other systems subject to limiting safety system settings to initiate the required protective function by the time a monitored parameter reaches the setpoint specified as the limiting system setting in the technical specifications or failure to complete the required protective function. ! HOTE: Instrument drift discovered as a result of testing need not be l reported under this item but may be reportable under items 2.a(5), l 2.a(6), or 2.b(1) below. l (2) Operation of the unit er affected systems when any parameter or operation subject to a limiting condition is less conservative than the least conservative aspect of the limiting condition for operation established in the technical specifications. NOTE: If specified action is taken when a system is found to be operating between the most conservative and the least conservative aspects of a limiting condition for operation listed in the technical specifications, the limiting condition for operation is not considered 6.1-12
4 g to .hsve bern violsted tnd netd not be reported undr.r this itam, but it may be reportable under item 2.b(2) below. (3) Abnormal degradation discovered in fuel cladding, reactor coolant pressure boundary, or-primary containment. o NOTE: Leakage of valve packing or gaskets within the limits for identified leakage set forth in technical specifications need not be l reported under this item. (4) Reactivity anormalies, involving disagreement with the predicted value of reactivity balance under steady state
, conditions during power operation, greater than or equal to 1%
delta k/k; a calculated reactivity balance indicating a shutdown margin less conservative than specified in the technical
- specifications; short-term reactivity increases that correspond to l a reactor period of.less than 5 seconds or, if sub-critical, an j unplanned reactivity insertion of more than 0.5% delta k/k or l occurrence of any unplanned criticality.
(5) Failure or malfunction of .one or 'more components which -! prevents or could prevent, by itself, the- fulfillment of the l functional requirements of system (s) used to cope with accidents j analyzed in the SAR. (6) Personnel error or procedural inadequacy which prevents or could prevent, by itself, the, fulf111 ment of the functional requirements of -systems required to cope with accidents analyzed in the SAR. , l NOTE: For items 2.a(5) and 2.a(6) reduced redundancy that does not result in a loss of system function need not be reported under- this i section but may be reportable under items 2.b(2) and 2.b(3) below. (7) Conditions arising from. natural or man-made events that, as a
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direct result of the event require plant shutdown, operation of - safety, systems, or other protective measures required by technical specifications. (8) Errors discovered in the transient or accident. analysis or.in methods used for such analysis as described in the . safety report or in the bases for the technical specifications that has or could. have permitted reactor operation in-.a manner 'less conservative than assumed in the analysis. I i (9) Performance of structures, systems, or- components that-requires remedial action or corrective 1 measures to- prevent. operation in a- manner . lass conservative than assumed in the accident analysis in the safety analysis' report or technical - specifications bases; or discovery during plant life of conditions' not specifically considered- in.the- safety -analysis:, report .or technical ~ specifications that- require remedial action or. corrective measures to' prevent the existence or development.of. an unsafe condition.' NOTE: This item is not intended to provide for the reporting of potentially generic problems. 6.1-13.
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- b. Thirty Day Written Reperts. The reportabic occurrences discussed below shall be the subject of Hritten reports to the Director of the appropriate Regional Office within thirty days of occurrence of the event. The written report shall include, as a minimum, a complete copy of a licensee event report form. Information provided on the licensee event form shall be supplemented, as needed, by additional narrative material to provide complete explanation of the circumstances surrounding the event.
(1) Reactor 5-3ttetion system or engineered safety feature instrument setcl- s which are found to be less conservative than those established by the technical specifications but Hhich de not prevent the fulfillment of the functional requirements of affected systems. (2) Conditions leading to operation in a degraded mode permitted by a limiting condition for operation or plant shutdown required by a limiting condition for operation. NOTE: Routine surveillance testing, instrument calibration, or preventive maintenance Hhich require system configurations as described in items 2.b(1) and 2.b(2) need not be reported except where test results themselves reveal a degraded mode as described above. (3) Observed inadequacies in the implementation of administrative or procedural controls which threaten to cause reduction of degree of redundance provided in reactor protection systems or engineered safety feature systems. (4) Abnormal degradation of systems other than those specified in item 2.a(3) above designed to contain radioactive material resulting from the fission process. NOTE: Sealed sources or calibration sources are not included under this item. Leakage of valve packing or gaskets within the limits for identified leakage set forth in technical specifications need not be reported under this item. 6.9.3 UNIQUE REPORTIMG REQUIREMENTS Special reports shall be submitted to the Director of Regulatory Operations Regional Office Hithin the time period specified for each report. These reports shall be submitted covering the activities identified belon pursuant to the requirements of the applicable reference specification.
- a. Materials Radiation Surveillance Specimen Reports (4.3A)
- b. Integrated Primary Containment Leakage Tests (4.5)
- c. Semi-annual reports specifying effluent release shall be submitted -
to the NRC. These reports shall include the following: (1) Radioactive Effluent Releases 6.1-14 9
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A statement of th2 quantitiss of rrdioactiva cffluents reistsId from the plant Hith data summarized on a monthly basis follouing the format of USAEC Guide 1.21. (a). Gaseous Effluents
- 1. Gross Radioactivity Releases
- a. Total gross radioactivity (in curie:),
primarily noble and activation gases.
- b. Maximum gross radioactivity relcase rate during any one-hour period.
- c. Total gross radioactivity (in curies) by j nuclide release based on representative isotopic analysis performed. ,
- d. Percent of technical specification limit. !
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- 2. Iodine Releases
- a. Total iodine radioactivity (in curies) by nuclide releases based on representative isotopic analysis performed.
- b. Percent of technical specification limit for I-131 released.
- 3. Particulate Releases
- a. Total gross radioactivity (Beta, Gamma) released (in curies) excluding background radioactivity.
_ b. Gross alpha radioactivity released.(in curies) excluding background radioactivity.
- c. " Total gross radioactivity (in curies) of nuclides Hith half-lives greater than eight days.
- d. Percent of technical specification limit for-particulate radioactivity Hith half-lives greater than eight days.
- 4. Liquid Effluents
- a. _ Total' gross. radioactivity (Beta, Gamma)
' released (in curies) excluding tritium and .-average.
-concentration released to the unrestricted area.
L b'. The. ~ maximum. concentration of ~ gross - radioactivity (Beta, Gamaa) released to the unrestricted area (averaged over the period of release).
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- c. Total tritium and totti cipha rcdioactivity (in curies) released and average concentration ,
released to the unrestricted area. <
- d. Total dissolved gas radioactivity (in curies) and averaged concentration released to the l unrestricted area. i l
- e. Total volume (in liters) of liquid Haste released.
- f. Total volume (in liters) of dilution Hater used prior to release from the restricted crea.
- g. Total gross radioactivity (in curics) by nuclide released based on representative isotepic analysis performed.
- h. Percent- of technical specification limit for total radioactivity.
(2) Solid Haste (a). The total amount of solid Haste shipped (in cubic feet). (b). The total estimated radioactivity (in curies) involved. (c). Disposition including date and destination. (3). Environmental Monitoring (a). For each medium sampled during the reporting period, e.g., air, baybottom, surface Hater, soil, fish, include:
- 1. Number of sampling locations.
- 2. Total number of samples.
- 3. Number of locations at which levels are found to be significantly above local backgrounds, and
- 4. Highest, lowest, and the average concentrations or level of radiation for the sampling point Hith the highest average and description of the location of that
- point Hith respect to the site.
! (b). If levels of radioactive materials in environmental media as determined by an environmental monitoring pregram indicate the likelihood of public intakes in excess of 1% of those that could result from continuous exposure to the concentration values listed in Appendix B Table II, Part 20 estimates of the likely resultant exposure to individuals and to population groups, and assumptions upon which estimates ! are based shall be provided. (c). If statistically significant variations of offsite environmental concentrations with time are observed, 6.1-16
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1 corrclaticn of thes2 results With Gffluent r31S T2 shall be provided. (d). Results .of required leak tests performed on sealed O sources if the tests reveal the presence of 0.005 microcuries or more of removeable contamination. (e). Inoperable Fire Protection Equipment (3.12) (f). Core Spray Sparger Inservice Inspection (Table 4.3.1-9) Prior to startup of each cycle, a special report presenting the results of the inservice inspection of the Core Spray Spargers during each refueling outage shall be submitted to the Commission for review. 6.10 RECORD RETENTION 6.10.1 The following records shall be retained for at least five years:
- a. Records and logs of facility operation covering time interval at each power level.
- b. Records and logs of principle maintenance activities, inspections, repair and replacement of principle items of equipment' related ~to nuclear safety.
- c. Reportable occurrence reports.
- d. Records of surveillance activities, inspections and calibrations required by these technical specifications..
- e. Records of reactor tests and experiments.
- f. Records of changes made to operating procedures,
- g. Records of radioactive shipments,
- h. Records of sealed source leak tests and results.
- i. Records of annual physical inventory of all source material of record.
6.10.2 The folloHing records shall be retained for the duration of the Facility Operating License:
- a. Racord and 'draHing changes reflecting facility design modifications made to systems and equipment described in 'the. Final -
Safety Analysis Report.
- b. Records of neH and irradiated fuel inventory, fuel transfers and assembly burnup histories.
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- c. R; cord 2 of f;cility radiition cnd contamination surv;ys.
- d. Records of radiation exposure for all individuals entering radiation control areas.
- c. Records of gaseous and liquid radioactive material released to the environs.
- f. Records of transient or operational cycles for those facility components designed for a limited number of transients or cycles.
- g. Records of training and qualification for current members of the plant staff.
- h. Records of inservice inspections performed pursuant to these technical specifications.
- 1. Records of reviews performed for changes made to procedures or equipment or reviews of tests and experiments pursuant to 10 CFR 50.59.
- j. Records of meetings of the Plant Operations RevicH Committee and the General Office Revien Board.
- k. Records for' Environmental Qualification which are covered under the provisions of paragraph 6.14.
6.10.3 Quality Assurance Records shall be retained as specified by the Quality Assurance Plan. 6.11 RADIATION PROTECTION PROGRAM Procedures for personnel radiation protection shall be prepared consistent with the requirements of 10 CFR 20 and shall be approved, maintained and adhered to for all operations involving personnel radiation exposure. 6.12 (Deleted) 6.13 HIGH RADIATION AREA 6.13.1 In lieu of the " control device" or " alarm signal" required by paragraph 20.203(c)(2) of 10 CFR 20, each high radiation area in which the intensity of radiation is greater than 100 crem/hr but less than 1000 crem/hr shall be barricaded and conspicuously posted as a high radiation area and entrance thereto shall be controlled by requiring l issuance of a Radiation Hork Permit (RUP). l Health Physics personnel shall be exempt from the RHP
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l HOTE: Issuance requirement during the performance of their assigned radiation protection duties, provided they are following plant radiation protection procedures for entry into high radiation areas. 6.1-1E O l l: 4 e . _ 1 1 m - , o
An individu:1 or grcup of individuels p;rmittid to cntsr such cr:2s i shall be provided Hith one or more of the folloWing: '
- a. A radiation monitoring device Hhich continuously indicates the radiation dose rate in the area.
- b. A radiation monitoring device which continuously integrates the
, radiation dose rate in the area and alarms When a pre-set integrated dose is received. Entry into such areas With this monitoring device , may be made after the dose rate levels in the area have been established and personnel have been made knoHledgeable of them.
- c. A health physics qualified individual (i.e. qualified in radiation protection procedures) Hith a radiation dose rate monitoring device who is responsible for providing positive exposure control over the activities within the area and Hho Hill perform periodic radiation.
surveillance at the frequency in the RWP. The surveillance frequency Hill be established by the Radiological Controls Manager. 6.13.2 i Specifications 6.13.1 shall also apply to each high radiation area in which the intensity of radiation is greater than 1000 mrem /hr. In
- addition, locked doors shall be provided to prevent unauthorized entry i
into such areas and the keys shall be maintained under the administrative control of operations and/or radiation protection supervision on duty. 6.14 EfNIRONMDITAL CUALIFICATION - Q A. By no later than June 30, 1982 all safety-related electrical Q equipment in the facility shall ba qualified in eccordance- with the provisions of : Division of Operating Reactors " Guidelines for l Evaluating Environmental Gualification of Class IE Electrical Equipment in Operating Reactors" (DOR Guidelines); or, HUREG-0588 " Interim Staff Position on Environmental Qualification of Safety-Related Electrical Equipment", December 1979. Copies of these documents are attached to Order for Modification of License DPR-16 dated October 24, 1980. B. By no later than December 1, 1980, complete and auditible records must be available and maintained at a central location which: ' describe the environmental qualification method used for all safety-related electrical equipment in sufficient detail to document the degree of compliance with the DOR Guidelines or HUREG-0588. Thereafter, such records should be updated and maintained current as equipment is replaced, further tested, or otherHise further qualified. 6.15 INTEGRITY OF SYSTEf;S OUTSIDE CONTAINMENT i The licensee shall implement a program to reduce leakage from systems outside containment that would or could contain highly radioactive fluids during a serious transient or accident to as.loH as practical levels. This program shall include the folloHing. l (1). Provisions establishing preventive maintenance and periodic visual inspection requirements, and *' 1 6.1-19 ! i
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(2). Syst m 1:ak t:st r;quir; ment 2, to the cxt;nt p:;rmittid by system design and radiological conditions, for each system at a frequency not to exceed refueling cycle intervals. The systems subject to this testing are (1) Core Spray, (2) Containment Spray, (3) Reactor Water Cleanup, (4) Isolation Condenser and (5) Shutdown Cooling.
, 6.16 IODINE MONITORING The licensee shall implement a program which Hill 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.
- Areas requiring personnel access for establishing hot shutdown conditions.
O l 6.1-20 I l'
T ABL E 3.1.1 PROTECTIVE INSTPUMENT ATIDH REQUIREMENTS Min. No. of Min. No. of Operable Reactor Modes Operabia or Instrument In which Function Operating Channels Per Must Pa Onareble (Tripped) Operable Trip Settina shutdown Refunt Startup Run Trip Systems Trin Svstems Action RequiredM Function A. Scram Insert control rods
- 1. Manual Scram X X X X 2 1
- 2. High Reactor MM X(s) X X 2 2 .
Pressure
- 3. High Drywell less than or : to X(u) X(u) X 2 2 Pressure 2 psig
- 4. Low Reactor MM X X X 2 2 Water Level
- 5. High Water less than or : to X(a) X(z) XCz) 2 2 Level in 37 gal.
Scram Dis-charge Volume
- 6. Low Condenser greater than or : to XCb) X(b) X 2 2 Vacuum 23" Hg
- 7. High Radiation less than or : to X(s) X X 2 2 in Main Steam- 10 x normal back-line Tunnel ground
- 8. Average Power WM X(c,s) X(c) X(c) 2 3 Range Monitor i
( april)
- 9. Intermediate MM X(d) X(d) 2 3 Range Monitor (IRil)
MM X(b,s) X(b) X 2 4
- 10. Main Steamline !
Isolation Valve 4 Closure
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- 11. Turbine Trip MM XC3) 2 4 Scram
- 12. Generator WM X(j) 2 2 Load Rejection Scram C
L O O e
e O O TABLE 3.1.1 PROTECTIVE INSTRUMENTATION REQUTREMENTS O Min. No. of Min. No. of Operable Reactor Modes Operable or Instrument In which Function Operating Channels Per Must 0 _Oncreble (Tripped) Operable Function Yrio Settino Shutdown Refuel Startup Run Trip Systems Trip Systems Action ReautredW Close main steam B. Reactor Isolation isolation valves
- 1. Low-Low Reactor WW X X X X 2 2 and close isola-Water Level tion condenser vent valves, or High Flow in -less than or : to X(s) X(s) X X 2 2 place in cold
- 2. shutdown condition Main Steamline A 120% rated
- 3. Hign Flow in less than or : to XCs) X(s) X X 2 2 ,
Main Steamline B 120% rated
- 4. High Tempera- less than or : to X(s) X(s) X X 2 2 ture in Main Ambient at Steamline Power + 50 F Tunnel MM X 2 2
- 5. Low Pressure In Main Steamline High Radiation less than or : to X(s) X(s) X X 2 2 6.
in Main Steam 10X Normal Tunnel Background C. Isolation Condenser NN X(s) XCs) X X 2 2 Place plant in 1.. High Reactor '- cold shutdown s Pressure condition ' Low-Low Reactor greater than or : to X(s) X(s) X X 2 2
- 2. ?
Water Level. 7'2" above top of active fuel Consider the D. Core Sorav respective core - XCt)- X(t) X(t) X 2 2 spray loop in-
- 1. Low-Low Reactor NN-operable, & com-Water Level ply with Spec. 3.4 ~'
High Drywell less than or : to X(t) X(t) X(t) X 2(k) 2(k) 2. Pressure 2 psig
- 3. ' Low Reactor creater than or : to XCt) XCt) XCt) X 2 2 Pressure (valve 285 psig permissive) 7 L
TABLE 3.1.1 PPOTECTIVE INSTRUMFHTATION _ REQUIREMENTS Min. No. of Min. No. of Operable Reactor Modos Operable or Instrument In uhich Function Operating Channels Per tiust Pa Ororchjo (Tripprd Operable Shutdown Refool Startun Run Trin Svstems Trip Systems Action RequiredW Function Trin Settinn E. Santainment Sorev Consider the con-tainement spray
- 1. High Drywell less than or : to X(u) X(u) XCu) X 2(k) 2(k) loop inoperable Pressuro 2 psig and comply with Spec. 3.4
- 2. Low-Low Reactor greater than or : to X(u) X(u) X(u) X 2 2 Water Level 7'2" above top of active fuel F. Primary Containment Isointion Isolate contain-mont or place in
- 1. High Drywell less than or = to X(u) X(u) X(u) X 2(k) 2(k) cold shutdown Fressure 2 psig condition
- 2. Low-Low Reactor creater than or : to XCu) X(u) X(u) X 2 2 Water Level 7'2" above top of active fuel G. Automatie Denrossurization See note h
- 1. High Drywell less than or : to X(v) X(v) X(v) X 2(k) 2(k)
Pressure 2 psig
- 2. Low-Low-Low greater than or : to X(v) X(v) X(v) X 2 2 Reactor Water 4'8" above top of Level active fuel
- 3. AC Voltage NA X(v) X 2 2 Prevent auto depressurization on loss of AC power. See note i H. Isolation Condenser Isolation Isolate affected isolation con-X(s) X(s) X X 2 2 denser, comply
- 1. High Flow Steam less than or : to with Spec. 3.8
__ line 20 psi differential pressure
- 2. High Flow Con- less than or e to XCs) X(s) X X 2 2 densato Line 27" differentiel water
~. S 9 . e
O TABLE 3.1.1 PROTECTIVE INSTRUMENTATION REQUIREMENTS o ' Min. No. of Min. No. of Operable Reactor Modes Operable or Instrument In which Function Operating Channels Per Must Ba Ororeblo (Tripped) Operable Function Trio settino Shutdown ectual Startup Run Trip Svstems Trip Systems Action Reautrodu I. Offcas System Isolation Isolate reactor or trip the , X(s) X(s) X X 1 2 inoperable in-
- 1. High Radiation less than or : to strument channel in Offgas Line 10 x stack (e) Release limit (See 3.6-A.1)
Isolate Reactor J. Reactor Buildino Isolation and Bldg. 8 Initiate Standbv Gas Treatment Svstem Standby Gas Treat-Initiation ment System, or Manual Surv '11-X(w) X(w) X 1 1 ance for not more
- 1. High Radiation less than or : to than 24 hours Reactor Building 100 Mr/Hr.
Operation Floor (total for all in-struments under J) Reactor Bldg. less than or : to X(w) XCw) X X 1 1 in any 30-day
- 2. period Ventilation 17 Mr/Hr Exhaust
- 3. High Drywell less than or : to X(u) X(u) X X 1(k) 2(k)
Pressure 2 psig greater than or : to X X X X 1 2
- 4. Low-Low Reactor Water Level 7'2" above top of active fuel l No control rod K. Rod Block uithdrauals SRM Upscale less than or : to X XC1) 1 3(y) permitted 1.
5.0 E5 cps greater than or : to X X(1) 1 3(y)
- 2. SRM Downscale 100 cps (f) greater than or : to X X 2 3
- 3. IRM Downscale 5/125 fu11 scale (g)
- 4. APRM Upscale NN X(s) X X 2 3(c) greater than or : to X 2 3(c)
'5. 'APRM Downscale 2/150 fu11 scale IRM Upscale' .less than or : to X X 2 3 6. ~~
l i I l-i g 1
- zny--- TABLE 3.1.1 PROTECTIVE INSTRUMENTATION REQUIREMENTS Min. No. of Min. No. of Operable Reactor Modes Operable or Instrument In which Function Operating Channels Per Must Bn Orprnble (Tripped) Operable Trio Settino Shutdoim Rnfuni Startup Run Trip Systems Trip Systems Action Requiredw Function 103/125 fu11 scale
- 7. Scram Discharge Volume a) !!ater- level less than or : to high 18 gallons Xtz) X(z) XCz) 1 1
'L. Condenser Vacuum Insert control Pump Isolation rods
- 1. High Radiation less than or : to During Startup and 2 2 in Main Steam 10 x Hormal Run when vacuum Tunnel Background pump is operating M. Diesel Concrator Time delay after Consider contain-Load Scouence Timars energiz. of relay ment spray loop inoperable
- 1. Containment Spray 40 sec X X X X 2(m) 1(n) and comply with Pump plus or minus 15% Spec. 3.4.C (See note gl.
- 2. CRD Pump 60 sec X X X X 2(m) 1(n) Consider the pump plus or minus 15% inoperable and comply with Spec.
3.4.D (See Note q.) Emerg. Service 45 sec. X X X X 2(m) 1(n) Consider the loop
- 3. inoperable and Water Pump (r) plus or minus 15%
comply with Spec. 3.4.C (See Hote q) (SK1A) 120 sec (SK2A) X X X X 2(o) 2(p) Consider the pump
- 4. Service Water inoperable and Pump (aa) plus or minus %15 10 sec (SK7A) comply within 7 plus or minus %15 days (See Hote q).
~~
(SK8A Closed Cooling 166 sec X X X X 2(m) 1(n) Consider the pump
- 5. inoperable and Water Pump (bb) plus or minus 15%
comply within 7 days (See note q).
~~
9 9 e
s
\
O TABLE 3.1.1 PROTECTIVE INSTRUMENTATION REQUIREMENTS Min. No. of . Min. No. of Operable ! Operable or' Instrument Reactor Modes In which Function Operating Channels Per Must Bo Operabic' (Tripped) Operable ' Function Trip Settino Shutdown Refuel Startup Run Trip Systems Trip Systems Action Reautredu Du iAction required when minimum conditions for operation are not satisfied. Also permissible to trip inoperable trip system. When 2 . necessary to conduct tests and calibrations, one channel may be made inoperable for up to one hour per month without tripping its trip system. NN Sce Specification 2.3 for Limiting Safety System Settings. Motes *
- n. Pcruissible'to. bypass, with control rod block, for reactor protection system reset in refuel mode.
~!
.b;-Permissible to bypass'below 600 psig in refuel and startup modes.
' c.1Dne'(1),APRM in each operable trip system may be bypassed or inoperable provided the requirements of Specification 3.1.C and 3.10.D are satisfied. Two APRM's in the same quadrant shall not be concurrently bypassed except as noted below 'r er-permitted by note.
.Any one APRM may be removed from service for up to one hour for test or calibration without inserting trips in its trip '., '
system only if the remaining operable APRM's meet the requirements of Specification 3.1.B.1 and no control rods are moved eutwerd during the calibration or, test. During this short period,-the requirements of Specifications 3.1.B.2, 3.1.C and 3.19.D~ 4-
.n=ed not be met.
- d.:The (IRM)s hall'be inserted.and operable until the APRM's are operable and reading at least 2/158 full scale.
- o. ' Air " ejector isolation . valve ' closure time delay 'shall not exceed 15 minutes.
- f. Unless SRM chambers are fully inserted.
- g. Hot l applicable when IRM on. lowest range. +;
h.,0ne instrument channel in each trip system may be inoperable provided the circuit which it operates in the trip system is
'placed in a simulated tripped condition. If repairs cannot-be completed within 72 hours the reactor shall be placed in the ':
cold shutdown condition. If more than one instrument channel in any trip system becomes inoperable the reactor shall be placed.in the cold' shutdown condition. Relief valve controllers shall not be bypassed for more than 8 hours (tetal time for'all-controllers)~in any 30-day' period and only one relief valve controller may be bypassed at a time. 4
~
. ' ;i . :The interlock is not required during'the start-up test program and demonstration of plant electrical output but shall bek aprovidedLfo11owing these actions. Lj (Not-required below'40% of turbine. rated steam flow. }
'k. A11'four (4) drywell pressureLinstrument channels may be made inoperable during the integrated primary containment leakage
~
rate test (See Specification 4.5).. providad that the plant is in the cold shutdown condition and that no work is performed L en the reactor or its connected systems which could result in lowering the reactor water level to less than 4'8"above the top ff
~~ ~
~
t
-LN
.g
___g_____-.___________ TABLE 3.1.1 PROTECTIVE INSTRUMENTATION REQUIREMENTS Min. Ho. of Min. No. of Operable Reactor Modes Operable or Instrument In which Function Operating Channels Per Must Ba Operchin (Tripped) Operable , Function Trin Settino Shutdown Rofuel Startup Run Trip Svstems Trip Svstems Action ReautredW of the active fuel.
- 1. Bypassed in IRM Ranges 8, 9, 8 10.
- m. There is one time delay relay associated with each of two pumps. .a
- n. One time delay relay per pump must be operable.
- o. Thore ar e two time delay relays associated with each of two pumps. One timer per pump is for sequence starting (SK1A, SK2A) and one timor per pump is for tripping the pump circuit breaker (SK7A, SK8A).
- p. Two time delay relays per pump must be operable.
- q. Manual initiation of affected component can be accomplished after the automatic load sequencing is completed,
- r. Time delay starts after closing of containment spray pump circuit breaker.
.I
- s. These functions not required to be operable with the reactor temperature less than 212 F and the vessel head removed er vented. j
- t. These functions may be operable or bypassed when corresponding portions in the same core spray system logic train are inoperable per Specification 3.4.A.
- u. These functions not required to be operable when primary containment integrity is not required to be maintained.
- v. These functions not required to be operable when the ADS is not required to be operable. ,
- w. These functions must be operable only when irradiated fuel is in the fuel pool or reactor vessel and secondary containment j integrity is required per Specification 3.5.B. f
- y. The number of operable channels may be reduced to 2 per Specification 3.9-E and F.
- z. The bypass function to permit scram reset in the shutdown or refuel mode with control rod block must be operable in this mode.'
ca. Pump circuit breakers will be tripped in 10 seconds plus or minus 15% during a LOCA by relays SK7A and SK8A. 1 __bb. Pump circuit breakers will trip instantaneously during a LOCA. W e e - e- -
TABLE 3.3.1 PRIMARY COOLANT SYSTEM PRESSURE ISCLATION VALVES MAXIMUM (a) SYSTEM VALVE NO. ALLO'JABLE LEAKAGE Core Spray System 1 NZO2A 5.0 GPM NZO2C 5.0 GPM Core Spray System 2 NZO2B 5.0 GPM NZO2D 5.0 GPM Footnote: (a)
- 1. Leakage rates less than or equal to 1.0 gpm are considered acceptable.
Z. Leakage rates greater than 1.0 gpm but less than er equal to 5.0 gpm are considered acceptable if the latest measured rate has not exceeded the rate determined by the previous test by an amount that reduces the margin between measured leakage rate and the maximum permissibic rate of 5.0 gpm by 50% or greater.
- 3. Leakage rates greater than 1.0 gpm but less than or equal to 5.0 gpm are considered unacceptable if the latest measured rate exceeded the rate determined by the previous test by an amount that reduces the margin between measured leakage rate and the maximum permisssible rate of 5.0 gpm by 50% or greater.
- 4. Leakage rates greater than 5.0 gpm are considered unacceptable.
- 5. Test differential pressure shall not be less than 150 psid.
e I l' c _ a
TABLE 3.5.1 SAFETY RELATED SHUBBERS Snubbers Snubbers In Snubbers Snubbers Accessible High Radiation Especially Inaccessible During Snubber Area During Difficult During Normal Normal Humber Location Elevation Shut Down to Remove Operation Operation H-1-1 North Main Steam 23' X X H-1-2 North Main Steam 23' X X H-1-3 North Main Steam 51' X X H-1-4 Horth Main Steam 51' X X H-1-5 Horth Main Steam 51' X X . H-1-6 North Main Steam 51' X X H-1-7 Horth Main Steam 60' X X H-2-1 North Feedwater 23' X X H-2-2 Horth Feedwater 23' X X H-2-3 Horth Feedwater 51' X X H-2-4 Horth Feedwater 51' X X H-2-5 Horth Feedwater 51' X X H-2-6 Horth Feedwater 51' X X H-2-7 Horth Feedwater 51' X X H-2-8 North Feedwater 51' X X S-1-1 South Main Steam 23' X X S-1-2 South Main Steam 23' X X S-1-3 South Main Steam 51' X X S-1-4 South Main Steam 51' X X S-1-5 South Main Steam 51' X X S-1-6 South Main Steam 51' X X S-1-7 . South Main Steam 60' X X S-2-1 South Feedwater 23' X X S-2-2 South Feedwater 23' X X S-2-3 South Feedwater 51' X X S-2-4 South Feedwater 51' X X S-2-5 South Feedwater 51' X X S-2-6 South Feedwater 51' X - X S-2-7 South Feedwater 51' X X S-2-8 South Feedwater 51' X X H-14-1 Emergency Condenser Condensate Return 75' X X ~~ N-14-2 Emergency Condenser Condensate Return 75' X X H-14-3 Emergency Condenser Condensate Return 95' X X H-14-4 Emergency Condenser Condensate Return 95' X X H-14-5 Emergency Condonser Condensate Return 95' X X 7
. O O e
A TABLE 3.5.1 SAFETY RELATED SHUBBERS Snubbers Snubbers In Snubbers Snubbers Accessible High Radiation Especially Inaccessible During - Area During Difficult During Normal Normal Snubber to Remove Operation' Operation Number Location Elevation Shut Down N-14-6 Emergency Condenser X Condensate Return 95' x S-14-1 Emergency-Condenser X X Condensate Return 60' S-14-2 Emergency Condenser X Condensate Return 60' X S-14-3 Emergency Condenser X Condensate Return 95' X
'S-14-4
- Emergency Condenser X Condenser Return 95' X S-14 Emergency-Condenser X X Condenser Return 95' S-14-6 . Emergency Condenser X Condensate Return 95' X Cleanup 60' X X 16-1 X X 16-2 Cleanup 51'
-Cleanup. 55' X X 16-3 X 16-4' Cleanup 65' X North' Core Spray X X
,N-20-1
'N-20-2. North Core Spray 51'.
51' X X North Core Spray. 75' X X H-20-3 X N-20-4 . North Core Spray 75' X South Core Spray 90' X X S-20-1 X X ,
.5-20-2 South Core' Spray 95' '
. South Core Spray 95'. X X
.S-20-3 X
.N-E-1 North-Electromatic Relief 51' X X
N-E-2 North Electromatic. Relief 51' X X X
.5-E-1 South Electromatic Relief 51' X X S-E-2 South Electromatic Relief 51' X X S-E-3 . South Electromatic Relief 51' X X
~~21-1 Containment Spray 60' Containment Spray -19' X 1 X 2- Containment Spray -19' Containment Spray' -19' X 3 X
- 4. Containment-Spray -19' Containment Spray -19' X 5
7 m
, . y -- -, TABLE 3.5.1 SAFETY RELATED SHUBBERS Snubbers Snubbers In Snubbers Snubbers A%.essible High Radiation Especially Inaccessible During Snubber Area During Difficult During Normal Normal Humbar location Elevation to Remove Operation Operation Sh_ut_Down 6 Outside Torus Cont. Spray -19' X 7 Outside Torus Cont. Spray -19' X 8 Outside Torus Cont. spray -19' X 9 Outsida Torus Cont. Spray -19' X 10 Outside Torus Cont. Spray -19' X 12 Outside Torus Cont. Spray -19' X 13 Outside Torus Cont. Spray -19' X 14 Outside Torus Cont. Spray -19' X 15 Outside Torus cont. Spray -19' X 16 Outside Torus Cont. Spray -19' X 17 Outside Torus Cont. Spray -19' X 18 Core Spray -19' X X 19 Core Spray -19' X 1 Core Spray 20' X 2 Core Spray 20' X 3 Cont. Spray 20' X X 4 Cont. Spray 20' X X 5 Core Spray 20' X X 6 Core Spray 20' X X 1 Core Spray 23' X 2 Core Spray Pump 23' X 3 Cont. Spray 23' X 4 Cont. Spray 23' X 5 Cont. Sprav 23' X 6 Cont. Spray 23' X 7 Cont. Spray 23' X X 1 Cont. Spray 51' X 2 Cont. Spray 51' X 3 Cont. Spray 51' X 4 Cont. Spray 51' X 5 Core Spray 51' X 6 Core Spray 51' X 7 Core Spray 51' X 8 Core Spray 51' X 9 Core Spray 51' X 10 Core Spray 51' X 21 Core Spray 51' X 22 Core Spray 51' X 23 Core Spray 51' X 24 Core Spray 51' X
~~
G 9 e
m i'
.f u
. TABLE 3.5.1 O ,
J SAFETY RELATED SHUBBERS Snubbers Snubbers In Snebbers Snubbers Accessible High Radiation Especially Inaccessible - During Snubber Area During Difficult During Normal Normal Shut Down to Remove Operation Operation Number Location Elevation 1 Core Spray 75' x Core Spray 75' X
.'2 X 3 Core Spray 75' '
75' . X 4 Core Spray X 5 Core Spray 75' 75' X 6 B. Emer. Cona. X
~7 A. Emer. Cond. 75' X
8 A. Emer. Cond. 75' X
,9 B. Emer. Cond. 75' A.,Emer. Cond. 75' X 10 X 11 .A. Emer. Cond. 75' X
1:2 .A. Emer. Cond. 75' X 13 B. Emer. Cond. 75' X 14 .A. Emer. Cond. 75' X 15~ ~B. Emer.-Cond. 75' X. 16 A. Emer.-Cond. 75'. X 17 A. Emer. Cond. 75' X r , 18 A. Emer. Cond. 75' X 19 A. Emer. Cond. 75' X 20- A. Emer. Cond. 75' X
- 21. B. Emer. Cond. 75'-
X-
- 22 A. Emer..Cond. 75' X
23 A. Emer. Cond. 75' X i 24 A. Emer. Cond. 75' X 25 B. Emer. Cond. 75' X 1 -A. Emer. Cond. 95' X X 2 A. Emer. Cond. 95' X X F-3- A. Emer. Cond. 95' X A. Emer. Cond. 95' 4 5 B. Emer. Cond. 95' X c' X L 6 B. Emer. Cond. 95' X i
- B. Emer. Cond. 95' X ;
- 8 B. Emer. Cond. 95' X
9- B. Emer. Cond. 95' i: X X I?
""17-1. Shutdown Cooling 48' X X 't ,
17-2 Shutdown Cooling 51'. X X (" 17-3 Shutdown Cooling. 51' k Shutdown Cooling 51' X -X 17-4 X l.' 17-5L Shutdown Cooling- 51'. X X h 17-6' Shutdown Cooling 51' X 7 i
+
q.-
?! o.
r
- E r
TABLE 3.5.1 , i SAFETY RELATED SNUBBERS Snubbers Snubbers In Snubbers Snubbers Accessible High Radiation Especially Inaccessible During Snubber Area During Difficult During Hormal Hormal Elevation Shut Down to Remove Operation Operation Humber Location 51-7 Shutdown Cooling 51' X 51-8 Shutdown Cooling 51' X 51-9 Shutdown Cooling 51' X 51-10 Shutdown Cooling 51' - X 51-11 Shutdown Cooling 51' X 51-12 Shutdown Cooling 51' X Shutdown Cooling 51' X 51-13 X 51-14 Shutdown Cooling 51' Shutdown Cooling 51' X 51-15 X 51-16 Shutdown Cooling 51' Shutdown cooling X 51-17 51' X 51-18 Shutdown Cooling 51' Shutdown Cooling 51' X i 51-19 X 51-20 Shutdown Cooling 51' If radiation levels in the vicinity of snubbers change, appropriate modifications to this Table should be submitted to HRC as an cttrchment to any subsequent license amendment.
+
lt ' a-. G G e
. . __ _.m.
(1
' 'q) ~
TABLE 3.5ug
'CONTATHMENT I S O L A TI 9_N_V A1, V RS VALVE FUNCTION / VALVE DESIGNATION ISOLATION SIGNALS Main Steam Isolation Valves (NSO3A, NSO35, NSO4A, NSO4B) 1 l Main Steam condensate Drain Valves (V-1-106, V-1-107 V-1-110, V-1-111) 1 Reactor Building Closed Cooling Valves (V-5-147, V-5-166 V-5-167) 2 Instrument Air. Valve (V-6-395) , 1 .
Emergency Condenser: Vent Valves (V-14-1, V-14-5, V-14-19, 1-14-20) 1 Reactor Cleanup Valves (V-16-1, V-16-2,.V-16-14, V-16-61) 3
--Shutdown Cooling Valves (V-17-19, V-17-54) 3
.Drywell Equipment. Drain Tank. Valves CV-22-1, V-22-2) 3 7 .
Drywell Sump Valves (V-22-28 V-22-29) 3 Drywell 4 Torus Atmosphere Control (V-27-1, V-27-2, V-27-3, V-27-4, 3 , Valves- V-28-17, V-28-18, V-23-21. V-23-22. V-28-47, V-23-13, V-23-14. V-23-15, O a V-23-16. V-23-17, V-23-18, V-23-19, V-23-20) Reactor Recirculation loop Samr.le Valves (V-24-29, V-24-30) 1
' Torus to Reactor Building Vacuum Relief Valves (V-26-16, V-26-18) 3M [
;- )
- Traversing 'In-Core Probe Syster, (Tip machine ball valve- No. 1, No. 2, No. 3, No. 4) 3 3.
- n 1)Reector Isolation' Signals"as shown in Table 3.1.1
" "" 2) Low-Low Reactor Water Level and High Drywell Pressures or Low-Low-Low Reactor Water Level.
- 3) Primary Containment Isolation Signals.as shown in Table 3.1.1 NValves automatically: reset.to provide vacuum relief j z-J v
TABLE 3.6.1 DOSE FACTORS FOR EXPOSURE TO A SEMI-INFINITE CLOUD OF HOBLE GAS _ES Nuclide Ni* M_i+ i-l Kr-83m 2.88E-04 3.18E-08 l [ Kr-85m 1.97E-03 4.28E-06 Kr-85 1.95E-03 7.13E-08 Kr-87 1.03E-02 2.30E-05 Kr-88 2.93E-03 5.83E-05 , Kr-89 1.06E-02 4.68E-05 Kr-90 7.83E-03 4.41E-05 Xe-131m 1.11E-03 1.09E-06 Xe-133m 1.48E-03 8.98E-07 Xe-133 1.05E-03 8.26E-07 Xe-135m 7.39E-04 1.25E-05 Xe-135 2.46E-03 7.18E-06. Xe-137 1.27E-02 4.08E-06 Xe-138 4.75E-03 3.65E-05 i Ar-41 3.28E-03 4.40E-05
- mrad-m(3)/pci-yr Source: Regulatory Guide 1.109, Revision 1, October 1977, Table B-1' .
+ mrad /ci Source: Site specific finite plume gamma air dose factors from NRC RABFIN computer code.
\ .
T . - s j g Op.m J, Qgss c- .
, , ,; , ,, _. uy , .l l8
TABLE 3.6.2 THYROID DOSE FACTORS FOR INHALATION (Rii), GROUND PLANE EXPOSURE (Rgi), AND VEGETATION CONSUMPTION (Rvi) NUCLIDE Rii* Rgi=* Rvi** H-3 1.1E03 0 4.0 E03 C-14 6.7E03 0 1.8 E08 Na-24 1.6E04 1.9E07 3.7 E05 P-32 9.9E04 0 1.3 E08 Cr-51 8.5E01 4.7E06 6.5 E04 Mm-54 9.5E03 1.3E09 1.8 E08 Mm-56 3.1E-01 9.0E05 4.2 Fe-55 7.8E03 0 1.3 E08 Fe-59 1.7E04 2.8E08 3.3 E08 Co-58 3.2E03 3.8E08 2.0 E08 Co-60 2.3E04 2.1E10 1.1 E09 Ni-63 2.8E04 0 1.3 E09 Ni-65 1.6E-01 3.0E05 6.6 Cu-64 1.1 6.1E05 6.8 E03 Zn-65 7.0E04 7.5E08 1.3 E09 2n-69 8.9E-03 0 3.2 E02 Br-83 4.7E02 4.9 E03 5.7 Br-84 5.5E02 2.0 E05 3.8 E-11 Br-85 2.5E01- 0 2.6 E-13 Rb-86 1.1E05 3.4 E02 0 Rb-88 3.7E02 3.3 E04 3.1 E-22 Rb-89 2.9E02 1.2 EOS 3.5 E-26 Sr-89 1.7E04 2.3 E04 1.1 E09 Sr-90 6.4E06 0 3.2 Eli Sr-91 4.6 2.2 E06 2.1 E04 Sr-92 5.3E-01 7.8 E05 2.9 E01
- . I l' ;
_ - _ . _ _ _ _ = . 8
i I 1 l l TABLE 3.6.2 THYROID DOSE FACTORS FOR INHALATION (Rii), GROUND PLANE EXPOSURE (Rgi), AND VEGETATION CONSUMPTIDH (Rvi) NUCLIDE Rii* Rgi** Rvi** Y-90 1.1 E02 4.5 E03 6.2 E02 Y-91m 1.8E-02 1.0 E05 4.2 E-10 Y-91 2.4 E04 1.1 E06 5.0 EOS Y-92 5.8 E-01 1.8 E05 4.5 E i Y-93 5.1 1.9 E05 8.5 2r-95 3.7E04 2.5 E08 7.7 EOS 2r.-97 1.6E01 3.0 E06 4.9 E01 Hb-95 6.5E03 1.4 E08 1.1 E05 Ho-99 4.3 E01 4.0 E06 1.9 E06 Tc-99m 5.8 E-02 1.8 E05 1.6 E02 Tc-101 1.1 E-03 2.0 E04 6.9 E-30 Ru-103 1.1 E03 1.1 E08 5.9 E06 Ru-105 5.6E-01 6.4 EOS 3.3 E01 Ru-106 1.7 E04 4.2 E08 9.3 E07 Ag-110m 9.1 E03 3.5 E09 1.7 E07 Te-125m 1.9 E03 1.6 E06 9.8 E07 Te-127m 6.1 E03 9.2 E04 3.2 E08 Te-127 2.0 E02 3.0 E03 6.9 E03 Te-129m 6.3 E03 2.0 E07 2.8 EOS Te-129 7.1 E-02 2.6 E04~ 7.7 E-04 Te-131m 9.8 E01 8.0 E06 1.1 E06 . Te-131 1.7E 2.9 E04 1.4 E-15 Te-132 3.2E02- 1.0 EOS 2.5 E08
. I-130 1.8'E06 5.5 E06 7.0 E07
'+' I-131 1.6 E07 1.7 E07 -
'2.4 E10 c.- __
> s g. :.- ~ .. .,g x - . . ;l ,
if .
TABLE 3.6.2 THYROID DOSE FACTORS FOR INHALATION (Rii), GROUND PLANE EXPOSURE (Rgi), A!!D VEGETATIO!! CONSUMPTIO!! (Rvi) NUCLIDE Rii* Rgi** Rvi** I-132 1.9 EOS 1.2 E06 3.4 E03 I-133 3.8 E06 2.4 E06 3.9 E08 I-134 5.1 E04 4.4 E05 2.7 E-03 I-135 7.9 E05 2.6 E06 5.0 E06 Cs-134 2.2 EOS 6.8 E09 5.5 E09 Cs-136 1.2 E05 1.6 E02 1.6 E08 Cs-137 1.3 E05 1.0 E10 3.4 E09 Cs-138 5.6 E02 3.6 E05 5.8 E-11 Ba-139 5.4 E-02 1.1 EOS 1.4 E-03 Ba-140 4.3 E03 2.1 E07 1.6 E07 Ba-141 6.4 E-03 4.1 E04 2.9 E-23 Ba-142 2.8 E-03 4.6 E04 0 La-140 7.5 E01 1.9 E07 3.8 E02 La-142 1.3 E-01 7.4 E05 2.4 E-05 Ce-141 2.9 E03 1.4 E07 4.9 E04 Cc-143 2.9 E01 2.3 E06 1.3 E02 Ce-144 3.6 E05 6.9 E07 6.8 E06 Pr-143 9.1 E02 0 7.3 E03 Pr-144 3.0 E-03 1.8 E03 2.6 E-27 Nd-147 6.8 E02 8.5 E06 4.5 E03 H-187 4.3 2.4 E06 1.7 E04 Np-239 2.3 E01 1.7 E06 1.3 E02 O
~ _. . i i. 3
. .~ .. . = _ . . -. - - -
TABLE 3.6.2 4~ THYROID DOSE FACTORS FOR INHALATION (Rii), GROUND PLANE EXPOSURE (Rgi), AND VEGETATION CONSUMPTION (Rvi) HUCLIDE Rii* Rgi** Rvi**
- mrem-m(3)/uci-yr. .
** m(2)-mrem sec/uci-yr.
NOTE: Where no data was available for the thyroid dose factor in R.G. 1.109. Rev. 1, Tables E-9 or E-13, the total body dose factor was used to calculate Rii or Rvi, as applicable. Rvi factors for iodines were reduced by half based on the assumption that one-half the iodine released is non-elemental. (Per R.G. 1.109, Rev. 1. Page 26) 1 i 9 1 J l
.l i
0 l
+ I s
- m 4
NW.
- ma m ,.
~* -
*
- 5 ,
-- . . . , , g... ~ ; m,. , _ _
.g
TABLE 3.12.1 FIRE DETECTIO!! INSTRUMENTATIC!! Fire Required # Area /2cne Location Detecter Zone of Detceters 1 Rx. Bldg. 119' elev. Sprinkler Sys #10 1 (HFS) 1 95' NA 24* 1 75' HA 22* 1 75' Sprinkler Sys. #11 1 (HFS) 1 51' RK01/RK02 2 51' 1 - North 6+ 51' 2 - North 7+ 51' 1 - South 6+ 51' 2 - South 6+
" 38'/51' Shutdown Pu=p Rs. 7 1 23' 1 - North 6+
23' 2 - North 5+ 23' 1 - South 6+ 23' 2 - South 6+ 1
-19' "
HA 4 (1 per corner rm.) 3 4160 Swgr. Rm. Vault 2 (1 in "C" and 1 in "D") 4160 Swgr. Rm. Gen. Area 5 4160 Swgr. Rm. Battery Rm. 1 4 Cable Spread Rm. 4A-Zone 1 -3+ 4A-Zone 2 3+
" 4+
4B-Zone 3 4B-Zone 4 5+ 5 Control Room Gen. Area 5 A-Zone 1 3+ A-Zone 2 3+ B-Zone 1 7*+
% # $ 4 4 mW.r--== b e A-y a
, wvd N e., , e w I yag,p ,< ., . ,
l l l TABLE 3.12.1 FIRE CCTECTIO!! I?!STRUME!!TATIO!! Aren/ Zone Location Detector Zone of Detectors ) l l
" B-Zone 2 7*+ !
C-Zone 1 1+
" C-Zone 2 1+
Duct 1 6 480 Swgr. RM. Zone 1 9+
" Zone 2 8+
" 1 Corridor 7 "A" & "B" Battery Rm. Zone 1 4+
" 4+
Zone 2 Zone 4 (Duct) 1+ 8 HG Set Rm. NA 1 (HFS) 10 Monitor & Change Rm. Below Ceiling 2 Above Ceiling 10* Sprinkler Sys. #12 1 (HFS) 10/1 Laundry Room Sprinkler Sys. #13 1 (HFS) 11/3 Condenser Bay Sprinkler Sys. #2 1 (P.S.) 11/1 Turb. Lube Dil Deluge Sys. #3 1 (P.S.) 11/2 Turb. Basement South' Sprinkler Sys. 9 1 (HFS) 12 Transformers Deluge Sys. #1' 1 (P.S.) Deluge Sys. #2 1 (P.S.) 15 Emer. Diesel #1 Thermal 5-Ionization i~ -
-16 Fuel Storage Area NA i 17 Emer. Die'sel #2 Thermal 5~
Ionization 1 l O' 18 . Fire Water Pump House NA.
-4+
}.
~
+d' ). +- % + -
. m f , .
TABLE 3.12.1 FIRE DETECTIOil INSTRUMENTATIO?I Area / Zone Location Detector Zone of Detectors,
*No two adjacent detectors may be inoperable.
NFS - Water Flow Switch P.S. - Pressure Switch
+These detectors actuate automatic suppression systems.
O O
. . _ i ,. ,
es i TABLE 3.12.2 SPRAY / SPRINKLER SYSTEMS I Fire Area Locction System i Rx. Bldg. 119' Sprinkler Sys. #10 1 Rx. Bldg. 75' Sprinkler Sys. #11 1 Rx. Bldg. 51'-N Deluge Sys. #5 1 -S Deluge Sys. #6 1 Rx. Bldg. 23'-N Deluge Sys. #7
-S Deluge Sys. #8 4 Cable Spread Room Deluge Sys. #4A Deluge Sys. #4B 8 MG Set Room Sprinkler Sys. #4 10 Monitor & Change Rm. Sprinkler Sys. #12 10 Laundry Room Sprinkler Sys. #13 11 Condenser Bay Sprinkler Sys. #2
( ,j 11 Turbine Lube Oil Bay Deluge Sys. #3 11 Turbine Basement South Sprinkler Sys. #9 12 Transformers Deluge Sys. #1 Deluge Sys. #2 18 Fire Hater Pump House Deluge Sys. #9 t I l l 0
+" *
*dg *' -
TABLE 3.12.3 HOSE STATTOMS Fire Aren Zone Hose Station No. Locations 11 2 3 Turbine Basement - S 11 2 4 Turbine Basement - S 11 1 8 Turbine Basement - N 11 1 9 Turb. Basement - N 11 3 10 Condenser Bay 11 3 11 Condenser Bay 11 3 12 Condenser Bay 11 3 13 Condenser Bay 1 - 29 Rx Bldg. 23' 1 - 30 Rx Bldg. 23' 1 - 31 Rx Bldg. 23' 1 - 32 Rx Bldg. 23' 1 - 33 Rx Bldg. 23' 1 - 34 Rx Bldg. -19' 1 - 35 Rx Bldg. -19' 1 - 36 Rx Bldg. -19' 1 - 37 Rx Bldg. -19' 1 - 30 Rx Bldg. 51' 1 - 39 Rx Bldg. 51' 1 - 40 Rx Bldg. 51' 1 .- 41 Rx Bldg. 51' 1 - 42 Rx Bldg. 75' 1 - 43 Rx Bldg. 75' 1 - 44 Rx Bldg. 75' 1 - 45 Rx Bldg. 75' 1 - 46 Rx Bldg. 95' . 1 - 47 Rx Bldg. 95' < . _ 1. _ . ._
, i. a
,m...... i e i TABk,E3.1213HOSESTATICNS 4 Fire Area Zone Hose Station No. Locations 1 - 48 RX Bldg. 95' 4 1 Rx Bldg. 95' 1 - 49 4 1 - 50 Rx Bldg. 119' l I 1 - 51 Rx Bldg. 119' 4 - 52 Cable Room 5 - 53 Control Room i 10 1 54 Chem. Lab. 4 j -11 2 55 Turbine Basement S. 1 i l i i, 1 4 h t ( 4 ~ r W
- n. '#
- 5 $ ~
[' w u*,.. e . n .. , , , . y 3,
s TABLE 3.12.4 HALON SYSTEM Min. No. of Halon 1301 Sys. Fire Area Mention Charced Tanks
- 1. Battery Room A&B 7 Battery Room 1 (Office Bldg.)
Cable Tray Room Instrument Shop (Office Bldg.)
- 2. 480 Volt Switchgear 6 23' Elev. Between Rx.
Bldg. & Turbine Bldg. 3
- 3. Control Room Panels 5 Control Room 2 O
I I _l'
t
- i. .-
)
i l' TABLE 3.12.5 HYDRANTS AND HOSE HOUSES i j Fire Area' Hydrant No. ' Hose House'No. Locr* 'on i: 1 12, 15, 16,-17 3 5 Diesel Gen & l' Transformer Area i 14 2 2 Intake Structure 1 4 1 e i i ) i I i h a 1 i a 1 1 i i l i-l- f-
't / 3 4p'h Tv.. '- ., _Y-
#m f' [ + q+:s fsub .g ,
' ~
_ j4_,_ , >g, , :, "
,f '. -
TABLE 3.13.1 ACOIDDIT HONITORI!!G INSTRUMENTATION
- TOTAL NO. OF MINIMUM CHANNELS INSTRUMEf!T CHANNELS OPERABLE __
- 1. Relief Valve Position Indicator 1/ valve 1/ valve (Primary Detector *)
Cr Relief Valve Position Indicator 1/ valve (Backup Indications **) O
- Accoustic Monitor
** Thermocouple O\
a - .. _ i 18
w-TABLE 4.1.1 MINIMUM CHECK. CALIBRATION AND TEST FREQUENCY FOR PROTECTIVE INSTRUMENTATION Instrument Channal Check Calibrate Test Romarks (Annlios to Test end Calibration) 1
- 1. High Reactor Pressure HA 1/3 mo. Hote 1 By application of test pressure
- 2. High Drywell Pressure (Scram) HA 1/3 me. Note 1 By application of test pressure
- 3. Low Reactor Water Level 1/d 1/3 mo. Note 1 By application of test pressure
- 4. Low-Low Water Level 1/d 1/3 mo. Note 1 By application of test pressure
- 5. High Water Level in Scram NA 1/3 mo. Note 1 By varying level in switch columns Discharge Volume
- 6. Low-Low-Low Water Level NA 1/3 mo. Note 1 By application of test pressure
- 7. High Flow in Main Steamline 1/d 1/3 mo. Note 1 By application of test pressure
- 8. Low Pressure in Main NA 1/3 mo. Note 1 By application of test pressure Steamline
- 9. High Drywell Pressure 1/d 1/3 mo. Note 1 By application of test pressure (Core Cooling)
- 10. Main Steam Isolation Valve HA NA 1/3 mo. By exercising valve (Scram)
- 11. APRM Level HA 1/3d HA Dutput adjustment using operational type heat balance during power operation APRM Scram Trips Note 2 1/wk 1/wk Using built-in calibration equipment during power operation
- 12. APRM Rod Blocks Hote 2 1/3 mo 1/mo Upscale and downscale
- 13. a. High Radiation in Main 1/s 1/3 mo 1/wk Using built-in calibration equipment Steamline during power operation
- b. Sonsors for 13(a) HA Each refuel NA Using external radiation source ing outage
- 14. High Radiation in Reactor Building Operating Floor 1/s 1/3 mo. 1/wk Using gamma source for calibration Ventilation Exhaust 1/s 1/3 mo 1/wk Using gamma source for calibration
- 15. High Radiation on Air 1/s 1/3 mo 1/wk Using built-in calibration equipment Ejector Off-Gas
- 16. IRN Level NA Each HA During approach to shutdown only T
O O e 1
. . ,, .. - - ~ -- . - - . -- - . . .
( ( s
. s.
T ABL E 4.1.1
-MINIMUM CNECK. CALIBPATION AND TEST FREQUENCY FOR PROTECT _IVE INSTRUMENT ATION Instrument Channel Check Calibrate Test Remarks (Annlics to Test and Calibration) shutdown I;:
IRM Screm W W W Using built-in calibration equipment ,
- 17. IRM Blocks NA Prior to Prior to Upscale and downscale startup and startup and shutdown shutdown j
- 18. Condenser Low Vacuum HA Each refuel Each refuel .
Ing outage ing outage
- 19. Manual Scram Buttons NA NA 1/3 mo
- 20. High' Temperature Main NA Each refuel Each refuel Using heat source box Steamline Tunnel ing outage ing outage {!
N N Using built-in calibration equipment s'
- 21. SRM N
- 22. Isolation Condenser High NA 1/3 mo 1/3 mo By application of test pressure ff Flow Delta P (Steam and Water) 3 23.. Turbine Trip Scram NA NA Every 3 months 224. Generator Load Rejection N A. Every Every
. Scrams 3 months 3 months
.25. Recirculation Loop Flow NA Each refuel N A By appilcation of test pressure' ing outage }{
1; Every By application of test pressure 4;
- 26. Low Reactor Pressure .H A Every i:
; Core Spray Valve 3 months 3 months Permissive ,_j; 1
' 27. Scram Discharge Volume ,
d. (Rod Block) Each refuel-Every By varying level in switch column f
'a) Water level high- .HA 5, ing Outage 3 months i,
'Each refuel
~
b) Scram trip bypass ~ >N-A NA ing outage l: NOTE 1: -Initially once/mo, thereafter according to Fig. 4.1.1, with an interval not less than one month nor more than three } 2=snths. >. r. NOTE 2 -At least daily'during reactor' power operation, the reactor neutron flux peaking factor shall be estimated and the .' flew-referenced.APRM scram and' rod. block settings shall be adjusted, if necessary, as specified in Section 2.3, Specifications (1) ](3.. _m b-Q'
- r y,
T ABL E 4.1.1 MINIMUM CHECK. CALIBRATION AND TEST FREQUENCY FOR PROTECTIVE INSTRUMENTATION Instrument Channel Qheck Calibrate Test Romarks (Applies to Test and Calibration) (a) and (2) (a). N Calibrate prior to startup and normal shutdown and thereafter check 1/s and test 1/wk until no longer required. Leoendt NA: Not applicable; 1/s : Once por shift; 1/d : Once per day; 1/3d : Unce per 3 days;'1/wk = Once per week; 1/3 mo : Once every 3 months. M M O O O
TABLE 4.1.2 MINIMUM TEST FREGUEMCIES FOR TRIP SYSTEMS Trip System Minimum Test Frequency
- 1) Dual Channel (Scram) Same as for respective instru-mentation in Table 4.1.1
- 2) Rod Block
- 3) Containment Sprny, 1/3 mo. and each refueling "
each trip system, one at a time outage
- 4) Automatic Depressurimatien. Each refueling cutage each trip system, one at a time
- 5) MSIV Closure, each closure Each refueling cutage logic circuit independently (1 valve at a time)
- 6) Core Sprav,each trip system, 1/3 mo. and each refueling one at a time outage
- 7) Primary Centainment Isolation, Each refueling outage each closure circuit independently (1 valve at a time)
- 8) Refuelino Interlocks Price to each refueling operation
- 9) Isolation Condenser Actuation Each refueling outage and Isolation, each trip circuit independently (1 valve at a time)
- 10) Reactor Buildings Isolation and Same as for respective SGTS Initiation instrumentation in Table 4.1.1
- 11) Condenser Vacuum Pump Isolation Price to each startup 9
- I l'
TABLE 4.3.1 O EXAMINATION SCHEDULE OF REACTOR COOLANT SYSTEM (See Note 3) Inspection Inspection Process Frequency Component Samole Extent (See Note 1) (See Note 2) A. REACTOR VESSEL
- 1. Flange studs 100% -
Entire volirse' UT b from end Exposed surfaces VT b
- 2. Flange stud 100% VT ,
b washers and nuts
- 3. Steam nozzle One 100% nozzle to RT & a shell Hele g VT' 100% exterior VT a nozzle surface 100% nozzle to RT & a pipe Held VT
- 4. Core spray One 100% nozzle to VT a nozzle (exterice shell Held surface)
Safe end to VT a nozzle Held Safe end to VT a pipe Held
- 5. Control rod 10% Interior circum- U't c drive pene- selec- ference opposite trations ted of ~ housing to stub total tube Held
- 6. Recirculation One 100% safe end RT & .a inlet nozzle to nozzle dis- VT safe end Helds similar metal Held 100% s'afe end RT & a . . .
to pipe Held VT
- 7. Circumferential One. 10% of Held RT 4. a Held head to length inclu6- VT head flange ing 2 intersects C, - '
s l w .
s .
g gw. .m - + .sx . . .m. - . .- .
, s. ,..
- -=
TABLE 4.3.1 EXAMINATION SCHECULE CP REACTOR COOLANT SYSTEM (See Note 3) Inspection Inspection Process Frequency Component Sample Extent (See Note 1) (See Note 2) VT Examination by viewing
- 2. a. Inspect same sample twice during first 5 years of operation
- b. 100% inspect partial sample during at least two inspections such that 100% of the studs are inspected during the first 5 years of operation
- o. Inspect partial sample during at least two inspections such that 10%
of the penetrations are inspected during the first 5 years of operation
- d. Normal maintenance observations - Examination by viewing, where accessible, during maintenance.
- e. Full inspections of the accessible surfaces and Helds of both spargers and the repair assembly on core spray sparger no. 2 shall be carried out during each of the next five refueling outages beginning in 1979, subsequent inspections Hill be conducted at 5 year intervals.
- 3. The examination schedule of Tabic 4.3.1, extent of examination, inspection process, and inspection frequency shall be reviewed after the fourth year of cperation and a revised specification for subsequent inservice inspection developed.
.e . . c . _ _ , . .I - ._ l' _ _
g . . . . . . 1-
TABLE 4.3.2 f PRIMARY COOLANT SYSTEM PRESSURE ISOLATION VALVES Maximum (a) System Valve No. Allowable Lenknee l ~ l Core Spray System 1 ~NZOZA 5.0 GPM NZOZC 5.0 GPM Core Spray System 2 NZO2B 5.0 GPM NZO2D 5.0 GPM Footnote: I (a)1. Leakage rates less than or equal to 1.0 gpm are considered acceptable.
- 2. Leakage rates greater than 1.0 gpm but less than or equal to 5.0 gpm are considered acceptable if the latest measured rate has not exceeded the rate determined by the previous test by an amount that reduces the margin between measured leakage rate and the maximum permissible rate of 5.0 gpm by 50% or greater.
- 3. Leakage rates greater than 1.0 gpm but less than or equal to 5.0 gpm are considered unacceptable if the latest measured rate exceeded the rate determined by the previous test by an amount that reduces the margin between measured leakage rate and the maximum permissible rate of 5.0 gpm by 50%
or greater.
- 4. Leakage rates greater than 5.0 gpm are considered unacceptable.
i S. Test differential pressure shall not be less than 150 psid. l l
\ . .
4
~F b'
- h 6,"$ 5 % _t{-'W,A' ., $_ $ ?
kbg__gQ' y o,.g y ,,
~
, . _ = - .-. -. ... . _
g C k TAMLE 4.13.1 ACCIDENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS . CHANNEL CHANNEL INSTRtMENI CHECK CALIBRATION
- 1. Relief and Safety Valve Position Indicator A- 8 (Primary DetectorM)
Relief and Safety Valve Position Indicator A B (Backup IndicationsMM) 4 L Leoendr A: at least once per 31 days B at least once r,er 18 months (550 days). mAcoustic Monitor muThermoccuple , y , I
,p l $~
l 8-i Id 4- d . !! w 11
+
Y f: Y s
, -- ~q.
4 e t. 4
.i;
, h v 1
., l-j? -
y.-
... , _ . . _ . - . . , _ - . . _- .. _ _ _ __ _ . _ . . _ _ _ __ _ .___. __._ 1 J
~1A1 ' TARLE 6.5.1 SAFETY REVIEW RESPONSIBILITIES INDEPENDENT REVIEW ITEM INITIAL ACTION PORC ISRG SERR c) Proposed change to Initiator: Must prepare Must review items to Must review all deter- May review any deter-cquipment, or a ecmplete description determine whether or minations by the mination, but must cystems subject of the proposed not an unreviewed Vice president & review those for which to the Provisions changes and ensure safety question is Directo- the Vice President 8 ef Section 50.59, a safety evaluation of involved. If requested Director has requested Part 50, Title 10 the change is included, by the Vice President GORB review. Code of Federal Vice President 8 & Director Regulations. 8 Director (1) must determine if the item is an actual change to equipment or systems as described in the FSAR. (2) Must determine if the item involves an unre-viewed safety question. (3) May request the PORC to assist in the above determinations. b) Proposed tests and Initiator: Must prepare Must review item to As above. As above. cxperiments, (Sub- a complete description determine whether or
. cet to Provisions of the proposed test or not an unreviewed ef) 50.59, Part 50, experiment and ensure a safety question is Title 10, Code of safety evaluation of the involved, if requested Federal Regulations. test or experiment is by the Vice President included. 1 Director.
Vice President 8
. Director (1) Must determine if the item involves an unreviewed safety question. (2)
May request the PORC to assist in the above determinations. c) Proposed changes in Initiator: Must prepare (1) Must review the item Must review change and May review any item Technical Specifica- a complete description for nuclear and radiolo- PORC recommendation but must review those tions or in the HRC of the preposed change gical safety. (2) Must prior to submittal to for which the Vico Operating License. and ensure a safety make recommendations to the HRC. President & Director or evaluation of the change the Vice President 1 his supervisor have is included. Director as to whether requested GORB review. or not the change is safe. d) Reportable Vice President 1 Must review Reportable Must review Reportable As above. Occurrences Director: Must have Occurrences Report for Occurrence Reports for investigations performed safety significance and safety significance and for all Reportable make recommendations to review PORC recommenda-
~~
O O O
s V[N TABLE 6.5.1 SAFETY REVIEW RESPONSIBILITIES INDEPENDENT REVIEW
-ITig INITTAL ACTION PORQ ISRG GORB Occurrences and a report the Vice President 8 tions.
prepared including the Director on how to avoid safety significance of reccurrence. the incident.
.o)'Fccility operations Continuing responsibility See Item i below As above including Security
. Plan, Emergency Plan cnd implementing procedures; review is to detect patential safety hazards. f) Significance Vice President & Review matter and report Perform independent As above eperation abnormal- Director Report such evaluation of safety review of PORC itles or deviations matters to the PORC ,ISRG significance to the ISRG evaluation. from normal and Coordinator and the and CORB. cxpected perfor- Chairman GORB. n:nce.
- 6) Any indication of As above As above As above As above
- cn unanticipated daficiency in some cepect of design cr operation of safety related
- structures, systems, cr components.
h)'PORC minutes and Review to determine if As above
- reports any matters discussed Involve unrelated i safety questions.
i) Audit Reports Review to determine if The report of the end HRC Inspection any matters reported management review of
' Reports. involved Violations of the QA Plan, initi-Technical Specifications ated by the Vice license requirements or President, and Director regulations or have any Oyster Creek in accor- ' ~""
nuclear or radiation dance with the Oper =tional safety implications. Quality Assurance Plan, shall be reviewed by the GORB with respect to technical and admini-strative safety issues.
~~
ll
h? g
+;
!;2
{} : - O
' h; ir, k!
1 (( ricoRE a.t.: h s. $~' + FUEL CLADDING INTEGRITY SAFETY LIMIT 2800 d i l l l l l l l i l l I l l l l l l l l l i t i l l l 11 I i l l l l 1 I l l 11111 I i l l l l l 111 l i l l l I l l l i l l l h !lf', R = = 1 E 3 3 jj' o A C 2400 5 1035 PSIA 3 i; . y = = 0 E 1250 PSIA
. '{1l: R = =
! l 2000 5 E
%1 P = =
0 = = 0 :_ . y = =
!.t -i 4 E 1600
= =
i l
> R - - !
q = =
- i. I 3 E P N = = 1
.T 4 1200 Z - tKiTES - C i
- t. RATED P0WER
- 1330 FPJTH l I N = 2. PhTED FLOU = 61.0 X 10:s6 L3/HR = '
P' E = 3. pes (Inc FAcToas c. SPECIFICATION VALUES (PFO)* = k G = -1. CORE FPESSUFE => 600 PSIA =
$ A 800 = 5. REACTOP UATEP LEVEL => 10' 7*' ABOVE =
.{ . y : TOP OF ACTIW FUEL {
$ A T
3- e FOR PEAKING FACT (45 GREATER THAN SPECIFICATION f = oALuES (Pros,sEE SPECIFICATION 2.1.A.2 = p ',; ' , 400 _ = - E 3 E 354 MU = s- = = li ' o Il l l l l l I I I l l l l l I l l l l I I I I I I I I l I I I I I I I I I l l I I I I I I I I I l l I I I I I I I I l I I l I l l I II' y, 0 to 20 30 40 50 60 70 i: CORE FLOW (X.10**6 LB/HR.) y ,; s s. f.
; i.
g
% i L,
V _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ ___
Figure 3.2.1 Sodium Pentaborate Solution Volume - Concentration Requirements 1I Ii i i i!
- I II I E I!'3 !I i i i t i ~ t ~1 TFI'! I i t i i t!It IfI IT II i i ii i I ! t
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I FIGURE 3.2.2 Sodium Pentaborate Solution Temperature Requirements 160 , , . . 150 , Solution temperatura must be equal to or greater than that - 140 - indicated by the curve a 130 , hw 120 , I S 110 , , . i! L -
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Figure 3.3.1 Oyster Creek Nuclear Generating Station Reactor Vessel Pressure / Temperature Limits For Up To Ten Effective Full Power Years of Core Operation 1400 1l l I i ! t i ie . t i i i 1 . . . I i I i * *it i .i6 1 1* ' 'i. i I I f I I
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- , FIGURE 3.14,1 , ,7 -/ , MAXIMUM ALLOUABLE APLHCR (5-LOOP OPERATION) 53
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NOTES TO Fif.Un . 2.1
- 1. The President of the CPU Nuclear Corput i L i c e. is a Soni
.iee Prusident .f ' Met-Ed and is a Vice President of JCPLI.. The E : ; u t i v s 'l or tioant i 3 Vice President of both JCP&L and Mod-Ed.
- 2. The Ceneral Of fice Review Board re por t s to and gets general direction f r . :t the Of fice of the President - GPU Uuclear Corporation. Ilowever, t h e CO P.11 h i s direct access to the Presidents, Chief Cxacutive Officers and Boards .f Directors of the Companies i nv o l v eri .
- 3. he project engineering, the shift technical .2 d v i s o r s , and l i c e n n i n t; functions assigned to eacn nuclear plant site will report to the Vice President Technical Functions.
4 The quality assurance, emergency planning a nd training functions assigned to each nuclear plant site will report to the Vice P r .i s i d e n t Nucle .r Assurance.
- 5. The security, materials management, personnel and gene ral administrative functions ascigned to each nuclear p l a,n t site will report to the Vi:e President Administration. .
- 6. The rad ia log ic al and of f site
- environm.:nt.11 control functions m ign.d to each nuclear plant site will report to the Vice President ita d i o l o g i c .11 .::al Environmental Controls.
- 7. ne conduct of all Oyster Creek modifications , repairs and constructi.n activities will' be the responsibility of the Maintenance and Construction Director - Oyster Creek who will report to the Vice President Maintenance and Construction.
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