ML021970092: Difference between revisions

3. GE Service Information Letter No. 330, including Supplement 1, Jet Pump Beam Cracks, June 9, 1980.

4. NUREG/CR-3052, Closeout of IE Bulletin 80-07: BWR Jet Pump Assembly Failure, November 1984.

JAFNPP B 3.4.2-5 Revision 0

S/RVs B 3.4.3 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.3 Safety/Relief Valves (S/RVs)

BASES BACKGROUND The ASME Boiler and Pressure Vessel Code (Ref. 1) requires the reactor pressure vessel be protected from overpressure during upset conditions by self-actuated safety valves. As part of the nuclear pressure relief system, the size and number of S/RVs are selected such that peak pressure in the nuclear system will not exceed the ASME Code limits for the reactor coolant pressure boundary (RCPB).

The S/RVs are located on the main steam lines between the reactor vessel and the first isolation valve within the drywell. Each S/RV discharges steam through a discharge line to a point below the minimum water level in the suppression pool.

The S/RVs can actuate by either of two modes: the safety mode or the relief mode. However, for the purposes of this LCO, only the safety mode is required. In the safety mode (or spring mode of operation), the spring loaded pilot valve opens when steam pressure at the valve inlet overcomes the spring force holding the pilot valve closed. Opening the pilot valve allows a pressure differential to develop across the main valve piston and opens the main valve. This satisfies the Code requirement.

Each S/RV can be opened manually in the relief mode from the control room by its associated two-position switch. If one of these switches is placed in the open position the logic output will energize the associated S/RV solenoid control valve directing the pneumatic supply to open the valve.

Seven of these S/RV solenoid control valves can also be energized by the relay logic associated with the Automatic Depressurization System (ADS). ADS requirements are specified in LCO 3.5.1, "ECCS-Operating." In addition each S/RV can be manually operated from another control switch located at the ADS auxiliary panel located outside the control room. These switches will energize a different S/RV solenoid control valve. The details of S/RVs pneumatic supply and mechanical operation in the relief mode are described in Reference 2.

APPLICABLE The overpressure protection system must accommodate the most SAFETY ANALYSES severe pressurization transient. Evaluations have determined that the most severe transient is the closure of all main steam isolation valves (MSIVs), followed by reactor (continued)

JAFNPP B 3.4.3-1 Revision 0

S/RVs B 3.4.3_

BASES APPLICABLE scram on high neutron flux (i.e., failure of the direct SAFETY ANALYSES scram associated with MSIV position) (Refs. 3 and 4). For (continued) the purpose of the analyses (Ref. 4), nine S/RVs are assumed to operate in the safety mode. The analysis results demonstrate that nine S/RVs are capable of maintaining reactor pressure below the ASME Code limit of 110% of vessel design pressure (110% x 1250 psig = 1375 psig). This LCO helps to ensure that the acceptance limit of 1375 psig (at the vessel bottom) is met during the most severe pressurization transient.

From an overpressure standpoint, the design basis events are bounded by the MSIV closure with flux scram event described above. Reference 5 discusses additional events that are expected to actuate the S/RVs.

S/RVs satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii)

(Ref. 6).

LCO The safety function of nine S/RVs are required to be OPERABLE to satisfy the assumptions of the safety analysis (Refs. 3 and 4). The requirements of this LCO are applicable only to the capability of the S/RVs to mechanically open to relieve excess pressure when the lift setpoint is exceeded (safety function).

The single nominal S/RV setpoint is established (Ref. 2) to ensure that the ASME Code limit on peak reactor pressure is satisfied. The ASME Code specifications require the lowest safety valve setpoint to be at or below vessel design pressure (1250 psig) and the highest safety valve to be set so that the total accumulated pressure does not exceed 110%

of the design pressure for overpressurization conditions.

The single nominal S/RV setpoint is set below the RPV design pressure (1250 psig) in accordance with ASME Code requirements. The transient evaluations in Reference 5 are based on this single setpoint, but also include the additional uncertainties of +/- 3% of the nominal setpoint to provide an added degree of conservatism.

Operation with fewer valves OPERABLE than specified, or with setpoints outside the analysis limits, could result in a more severe reactor response to a transient than predicted, possibly resulting in the ASME Code limit on reactor pressure being exceeded.

(continued)

JAFNPP B 3.4.3-2 Revision 0

S/RVs B 3.4.3 BASES (continued)

APPLICABILITY In MODES 1, 2, and 3, nine S/RVs must be OPERABLE, since considerable energy may be in the reactor core and the limiting design basis transients are assumed to occur in these MODES. The S/RVs may be required to provide pressure relief to discharge energy from the core until such time that the Residual Heat Removal (RHR) System is capable of dissipating the core heat.

In MODE 4, decay heat is low enough for the RHR System to provide adequate cooling, and reactor pressure is low enough that the overpressure limit is unlikely to be approached by assumed operational transients or accidents. In MODE 5, the reactor vessel head is unbolted or removed and the reactor is at atmospheric pressure. The S/RV function is not needed during these conditions.

ACTIONS A.1 and A.2 With less than the minimum number of required S/RVs OPERABLE, a transient may result in the violation of the ASME Code limit on reactor pressure. If the safety function of the inoperable required S/RVs cannot be restored to OPERABLE status, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to MODE 3 within 12 hours0.5 days 0.0714 weeks 0.0164 months and to MODE 4 within 36 hours1.5 days 0.214 weeks 0.0493 months . The allowed Completion Times are reasonable, based on operating experience, to reach required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.4.3.1 REQUIREMENTS This Surveillance requires that the required S/RVs open at the pressures assumed in the safety analysis of References 3 and 4. The demonstration of the S/RV safety function lift settings must be performed during shutdown, since this is a bench test, to be done in accordance with the Inservice Testing Program. The lift setting pressure shall correspond to ambient conditions of the valves at nominal operating temperatures and pressures. The S/RV setpoint is +/- 3% for OPERABILITY; however, the valves are reset to +/- 1% during the Surveillance to allow for drift.

(continued)

JAFNPP B 3.4.3-3 Revision 0

S/RVs B 3.4.3_

BASES SURVEILLANCE SR 3.4.3.2 REQUIREMENTS (continued) A manual actuation of each required S/RV is performed while bypassing main steam flow to the condenser and observing

> 10% closure of the turbine bypass valves to verify that, mechanically, the valve is functioning properly and no blockage exists in the valve discharge line. This can also be demonstrated by the response of the turbine control valves, by a change in the measured steam flow, or by any other method suitable to verify steam flow. Adequate reactor steam dome pressure must be available to perform this test to avoid damaging the valve. Also, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure when the S/RVs divert steam flow upon opening. Sufficient time is therefore allowed after the required pressure and flow are achieved to perform this test. Adequate pressure at which this test is to be performed is 970 psig (the pressure consistent with vendor recommendations). Adequate steam flow is represented by two or more turbine bypass valves open, or total steam flow > 106 lb/hr. These conditions will require the plant to be in MODE 1, which has been shown to be an acceptable condition to perform this test. This test causes a small neutron flux transient which may cause a scram in MODE 2 while operating close to the Average Power Range Monitors Neutron Flux-High (Startup) Allowable Value.

Plant startup is allowed prior to performing this test because valve OPERABILITY and the setpoints for overpressure protection are verified, per ASME Code requirements, prior to valve installation. Therefore, this SR is modified by a Note that states the Surveillance is not required to be performed until 12 hours0.5 days 0.0714 weeks 0.0164 months after reactor steam pressure and flow are adequate to perform the test. The 12 hours0.5 days 0.0714 weeks 0.0164 months allowed for manual actuation after the required steam pressure and flow are reached is sufficient to achieve stable conditions for testing and provides a reasonable time to complete the SR. If a valve fails to actuate due only to the failure of the solenoid but is capable of opening on overpressure, the safety function of the S/RV is considered OPERABLE.

The 24 month on a STAGGERED TEST BASIS Frequency ensures that each solenoid for each S/RV is alternately tested. The 24 month Frequency was developed based on the S/RV tests required by the ASME Boiler and Pressure Vessel Code,Section XI (Ref. 7). Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency. Therefore, the Frequency is acceptable from a reliability standpoint.

(co-n-t-inu5ed)

JAFNPP B 3.4.3-4 Revision 0

S/RVs B 3.4.3-BASES (continued)

REFERENCES 1. ASME, Boiler and Pressure Vessel Code,Section III.

2. UFSAR, Section 4.4.

3. UFSAR, Section 14.5.1.2.

4. UFSAR, Section 16.9.3.2.3.

5. UFSAR, Section 14.5.2.

6. 10 CFR 50.36(c)(2)(ii).

7. ASME, Boiler and Pressure Vessel Code,Section XI.

JAFNPP B 3.4.3-5 Revision 0

RCS Operational LEAKAGE B 3.4.4 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.4 RCS Operational LEAKAGE BASES BACKGROUND The RCS includes systems and components that contain or transport the coolant to or from the reactor core. The pressure containing components of the RCS and the portions of connecting systems out to and including the isolation valves define the reactor coolant pressure boundary (RCPB).

The joints of the RCPB components are welded or bolted.

Some joints in

1 inch piping are also threaded.

During plant life, the joint and valve interfaces can produce varying amounts of reactor coolant LEAKAGE, through either normal operational wear or mechanical deterioration.

Limits on RCS operational LEAKAGE are required to ensure appropriate action is taken before the integrity of the RCPB is impaired. This LCO specifies the types and limits of LEAKAGE. This protects the RCS pressure boundary described in 10 CFR 50.2, 10 CFR 50.55a(c), and UFSAR, Section 16.6 (Refs. 1, 2, and 3).

The safety significance of RCS LEAKAGE from the RCPB varies widely depending on the source, rate, and duration.

Therefore, detection of LEAKAGE in the drywell is necessary.

Methods for quickly separating the identified LEAKAGE from the unidentified LEAKAGE are necessary to provide the operators quantitative information to permit them to take corrective action should a leak occur that is detrimental to the safety of the facility or the public.

A limited amount of leakage inside the drywell is expected from auxiliary systems that cannot be made 100% leaktight.

Leakage from these systems should be detected and isolated from the primary containment atmosphere, if possible, so as not to mask RCS operational LEAKAGE detection.

This LCO deals with protection of the RCPB from degradation and the core from inadequate cooling, in addition to preventing the accident analyses radiation release assumptions from being exceeded. The consequences of violating this LCO include the possibility of a loss of coolant accident.

APPLICABLE The allowable RCS operational LEAKAGE limits are based on SAFETY ANALYSES the predicted and experimentally observed behavior of pipe cracks. The normally expected background LEAKAGE due to equipment design and the detection capability of the (continued)

JAFNPP B 3.4.4-1 Revision 0

RCS Operational LEAKAGE B 3.4.4_

BASES APPLICABLE instrumentation for determining system LEAKAGE were also SAFETY ANALYSES considered. The evidence from experiments suggests that, (continued) for LEAKAGE even greater than the specified unidentified LEAKAGE limits, the probability is small that the imperfection or crack associated with such LEAKAGE would grow rapidly.

The unidentified LEAKAGE flow limit allows time for corrective action before the RCPB could be significantly compromised. The 5 gpm limit is a small fraction of the calculated flow from a critical crack in the primary system piping. Crack behavior from experimental programs shows that leakage rates much greater than 5 gpm will precede crack instability (Refs. 4, 5, and 6).

The low limit on increase in unidentified LEAKAGE assumes a failure mechanism that produces relatively tight cracks in piping and components. Intergranular stress corrosion cracking (IGSCC) would be typical of tight cracks on stainless steel piping and components susceptible to IGSCC (Refs. 8 and 9). Inspection programs (Refs. 10 and 11) are in place to detect cracking of piping and components.

No applicable safety analysis assumes the total LEAKAGE limit. The total LEAKAGE limit considers RCS inventory makeup capability and drywell floor sump capacity.

RCS operational LEAKAGE satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii) (Ref. 7).

LCO RCS operational LEAKAGE shall be limited to:

a. Pressure Boundary LEAKAGE No pressure boundary LEAKAGE is allowed, because it is indicative of material degradation. LEAKAGE of this type is unacceptable as the leak itself could cause further deterioration, resulting in higher LEAKAGE.

Violation of this LCO could result in continued degradation of the RCPB. LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.

b. Unidentified LEAKAGE The 5 gpm of unidentified LEAKAGE is allowed as a reasonable minimum detectable amount that the drywell floor drain sump monitoring system can detect within a reasonable time period. Violation of this LCO could result in continued degradation of the RCPB.

(continued)

JAFNPP B 3.4.4-2 Revision 0

RCS Operational LEAKAGE B 3.4.4 BASES LCO c. Total LEAKAGE (continued)

The total LEAKAGE limit is based on a reasonable minimum detectable amount. The limit also accounts for LEAKAGE from known sources (identified LEAKAGE which may be detected by the drywell equipment drain sump monitoring system). Violation of this LCO indicates an unexpected amount of LEAKAGE and, therefore, could indicate new or additional degradation in an RCPB component or system.

d. Unidentified LEAKAGE Increase An unidentified LEAKAGE increase of > 2 gpm within the previous 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period indicates a potential flaw in the RCPB and must be quickly evaluated to determine the source and extent of the LEAKAGE. The increase is measured relative to the steady state value; temporary changes in LEAKAGE rate as a result of transient conditions (e.g., startup) are not considered. As such, the 2 gpm increase limit is only applicable in MODE 1 when operating pressures and temperatures are established. Violation of this LCO could result in continued degradation of the RCPB.

APPLICABILITY In MODES 1, 2, and 3, the RCS operational LEAKAGE LCO applies, because the potential for RCPB LEAKAGE is greatest when the reactor is pressurized.

In MODES 4 and 5, RCS operational LEAKAGE limits are not required since the reactor is not pressurized and stresses in the RCPB materials and potential for LEAKAGE are reduced.

ACTIONS A.1 With RCS unidentified or total LEAKAGE greater than the limits, actions must be taken to reduce the leak. Because the LEAKAGE limits are conservatively below the LEAKAGE that would constitute a critical crack size, 4 hours0.167 days 0.0238 weeks 0.00548 months is allowed to reduce the LEAKAGE rates before the reactor must be shut down. If unidentified LEAKAGE has been identified and quantified, it may be reclassified and considered as identified LEAKAGE; however, the total LEAKAGE limit would remain unchanged.

(continued)

JAFNPP B 3.4.4-3 Revision 0

RCS Operational LEAKAGE B 3.4.4k BASES ACTIONS B.1 and B.2 (continued)

An unidentified LEAKAGE increase of > 2 gpm within a 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period is an indication of a potential flaw in the RCPB and must be quickly evaluated. Although the increase does not necessarily violate the absolute unidentified LEAKAGE limit, certain susceptible components must be determined not to be the source of the LEAKAGE increase within the required Completion Time. For an unidentified LEAKAGE increase greater than required limits, an alternative to reducing LEAKAGE increase to within limits (i.e., reducing the LEAKAGE rate such that the current rate is less than the "2 gpm increase in the previous 24 hours1 days 0.143 weeks 0.0329 months " limit; either by isolating the source or other possible methods) is to evaluate service sensitive type 304 and type 316 austenitic stainless steel piping that is subject to high stress or that contains relatively stagnant or intermittent flow fluids and determine it is not the source of the increased LEAKAGE. This type of piping is very susceptible to IGSCC.

The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is reasonable to properly reduce the LEAKAGE increase or verify the source before the reactor must be shut down without unduly jeopardizing plant safety.

C.1 and C.2 If any Required Action and associated Completion Time of Condition A or B is not met or if pressure boundary LEAKAGE exists, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to MODE 3 within 12 hours0.5 days 0.0714 weeks 0.0164 months and to MODE 4 within 36 hours1.5 days 0.214 weeks 0.0493 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant safety systems.

SURVEILLANCE SR 3.4.4.1 REQUIREMENTS The RCS LEAKAGE is monitored by a variety of instruments designed to provide alarms when LEAKAGE is indicated and to quantify the various types of LEAKAGE. Leakage detection instrumentation is discussed in more detail in the Bases for LCO 3.4.5, "RCS Leakage Detection Instrumentation." Sump level and flow rate are typically monitored to determine actual LEAKAGE rates; however, any method may be used to quantify LEAKAGE within the guidelines of Reference 8. In (continued)

JAFNPP B 3.4.4-4 Revision 0

RCS Operational LEAKAGE B 3.4.4 BASES SURVEILLANCE SR 3.4.4.1 (continued)

REQUIREMENTS conjunction with alarms and other administrative controls, a 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Frequency for this Surveillance is appropriate for identifying LEAKAGE and for tracking required trends (Ref. 9).

REFERENCES 1. 10 CFR 50.2.

2. 10 CFR 50.55a(c).

3. UFSAR, Section 16.6.

4. UFSAR, Section 4.10.

5. UFSAR, Section 16.3.

6. DRF-E31-00029-3(E), Summary of the Design of the Leak Detection System (LDS) for New York Power Authority, James A. FitzPatrick Nuclear Power Plant, November 1997.

7. 10 CFR 50.36(c)(2)(ii).

8. UFSAR, Section 4.10.3.4.

9. Generic Letter 88-01, NRC Position on Intergranular Stress Corrosion Cracking (IGSCC) in BWR Austenitic Stainless Steel Piping, US Nuclear Regulatory Commission, January 1988.

10. UFSAR, Section 16.4.

11. UFSAR, Section 16.5.14.

JAFNPP B 3.4.4-5 Revision 0

RCS Leakage Detection Instrumentation B 3.4.5 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.5 RCS Leakage Detection Instrumentation BASES BACKGROUND The JAFNPP design basis (Ref. 1) requires means for detecting and, to the extent practical identifying the location of the source of RCS LEAKAGE. Reliable means are provided to detect leakage from the reactor coolant pressure boundary (RCPB) before predetermined limits are exceeded (Refs. 2 and 3).

Limits are established on abnormal leakage so that corrective action can be taken before unacceptable results occur (Ref. 4). Leakage detection systems for the RCS are provided to alert the operators when leakage rates above normal background levels are detected and also to supply quantitative measurement of leakage rates. The Bases for LCO 3.4.4, "RCS Operational LEAKAGE," discuss the limits on RCS LEAKAGE rates.

Systems for separating the LEAKAGE of an identified source from an unidentified source are necessary to provide prompt and quantitative information to the operators to permit them to take immediate corrective action.

LEAKAGE from the RCPB inside the drywell is detected by at least one of two independently monitored variables, such as sump pump flow and drywell gaseous and particulate radioactivity levels. The primary means of quantifying LEAKAGE in the drywell is the drywell floor drain sump monitoring system.

The drywell floor drain sump monitoring system monitors the LEAKAGE collected in the floor drain sump. This unidentified LEAKAGE consists of LEAKAGE from control rod drives, valve flanges or packings, floor drains, the Reactor Building Closed Loop Cooling Water System, and drywell air cooling unit condensate drains, and any LEAKAGE not collected in the drywell equipment drain sump. The drywell floor drain sump has instrumentation that supply level indicators in the control room.

The floor drain sump level instrumentation include switches that start and stop the sump pumps where required. A timer starts each time the sump is pumped down to the low level setpoint. If the sump fills to the high level setpoint before the timer ends, an alarm sounds in the control room, indicting a LEAKAGE rate into the sump in excess of a preset limit. In addition, the pump-out time is monitored and (continued)

JAFNPP B 3.4.5-1 Revision 0

RCS Leakage Detection Instrumentation B 3.4.5 BASES BACKGROUND whenever the pump-out time exceeds a preset interval (continued) (indicating an increase in leak rate) an alarm annunciates in the control room.

As the water which has been collected in the drywell floor drain sump is pumped out, the discharge flow is measured and total flow indicated by a flow integrator. The unidentified LEAKAGE and unidentified LEAKAGE increase are periodically calculated from this flow integrator. A flow recorder continually plots time versus discharge flow rate: an increase in leakage rate is also detectable by an increase in sump discharge flow time and an increased frequency in discharge flow cycles.

The drywell continuous atmospheric monitoring system continuously monitors the drywell atmosphere for airborne particulate and gaseous radioactivity. A sudden increase of radioactivity, which may be attributed to RCPB steam or reactor water LEAKAGE, is annunciated in the control room.

The drywell atmosphere particulate and gaseous radioactivity monitoring system is not capable of quantifying LEAKAGE rates. The sensitivity and response time of the system are a function of: location of the leak; amount of fission or corrosion product remaining in the atmosphere where they may be measured; plateout of these products in the sampling lines; effectiveness of the drywell coolers in reducing airborne concentrations; and the power level at the time of leakage occurrence (Ref. 3). The drywell continuous atmospheric particulate monitoring system is sufficiently sensitive to detect a reactor coolant leak of 1 gpm within 4 hours0.167 days 0.0238 weeks 0.00548 months . The drywell continuous atmospheric gaseous monitoring system, however, will not alarm for reactor coolant leaks (since there is no retention factor for noble gases in the reactor coolant). The drywell continuous atmospheric gaseous monitoring system will respond only if the leak is in the steam portion of the RCPB. Larger changes in LEAKAGE rates can be detected in proportionally shorter times (Ref. 5).

APPLICABLE A threat of significant compromise to the RCPB exists if the SAFETY ANALYSES barrier contains a crack that is large enough to propagate rapidly. LEAKAGE rate limits are set low enough to detect the LEAKAGE emitted from a single crack in the RCPB (Refs. 6 and 7). Each of the leakage detection systems inside the drywell is designed with the capability of detecting LEAKAGE less than the established LEAKAGE rate limits and providing appropriate alarm or indication of excess LEAKAGE in the control room.

(continued)

JAFNPP B 3.4.5-2 Revision 0

RCS Leakage Detection Instrumentation B 3.4.5-BASES APPLICABLE A control room alarm or indication allows the operators to SAFETY ANALYSES evaluate the significance of the indicated LEAKAGE and, if (continued) necessary, shut down the reactor for further investigation and corrective action. The allowed LEAKAGE rates are well below the rates predicted for critical crack sizes (Refs. 6 and 7). Therefore, these actions provide adequate response before a significant break in the RCPB can occur.

RCS leakage detection instrumentation satisfies Criterion 1 of 10 CFR 50.36(c)(2)(ii) (Ref. 8).

LCO The drywell floor drain sump monitoring system is required to quantify the unidentified LEAKAGE from the RCS. Thus, for the system to be considered OPERABLE, the flow monitoring portion of the system must be OPERABLE since this portion is capable of quantifying unidentified LEAKAGE from the RCS. The other monitoring systems (one channel each of the drywell continuous atmospheric particulate and drywell continuous atmospheric gaseous monitoring systems) provide early alarms to the operators so closer examination of other detection systems will be made to determine the extent of any corrective action that may be required. With the leakage detection systems inoperable, monitoring for LEAKAGE in the RCPB is degraded.

APPLICABILITY In MODES 1, 2, and 3, leakage detection systems are required to be OPERABLE to support LCO 3.4.4. This Applicability is consistent with that for LCO 3.4.4.

ACTIONS A.1 With the drywell floor drain sump monitoring system inoperable, no other form of sampling can provide the equivalent information to quantify leakage. However, the drywell continuous atmospheric monitors will provide indication of changes in leakage.

With the drywell floor drain sump monitoring system inoperable, but with RCS unidentified and total LEAKAGE being determined every 4 hours0.167 days 0.0238 weeks 0.00548 months (SR 3.4.4.1), operation may continue for 30 days. The 30 day Completion Time of Required Action A.1 is acceptable, based on operating experience, considering the multiple forms of leakage detection that are still available. Required Action A.1 is modified by a Note that states that the provisions of (continued)

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RCS Leakage Detection Instrumentation B 3.4.5_

BASES ACTIONS A.1 (continued)

LCO 3.0.4 are not applicable. As a result, a MODE change is allowed when the drywell floor drain sump monitoring system is inoperable. This allowance is provided because other instrumentation is available to monitor RCS leakage.

B.1 With one required drywell continuous atmospheric monitoring channel inoperable, SR 3.4.5.1 must be performed every 8 hours0.333 days 0.0476 weeks 0.011 months for the remaining OPERABLE drywell continuous atmospheric monitoring channel to provide periodic information of activity in the drywell at a more frequent interval than the routine Frequency of SR 3.4.5.1. The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months interval provides periodic information that is adequate to detect LEAKAGE and recognizes that other forms of leakage detection are available. However, this Required Action is modified by a Note that allows this action to be not applicable if both drywell continuous atmospheric monitoring systems are inoperable. Consistent with SR 3.0.1, Surveillances are not required to be performed on inoperable equipment.

C.1 and C.2 With both required gaseous and particulate drywell continuous atmospheric monitoring channels inoperable, grab samples of the drywell atmosphere must be taken and analyzed to provide periodic leakage information. Provided a sample is obtained and analyzed once every 12 hours0.5 days 0.0714 weeks 0.0164 months , the plant may be operated for up to 30 days to allow restoration of at least one of the two monitors.

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months interval provides periodic information that is adequate to detect LEAKAGE. The 30 day Completion Time for restoration recognizes that at least one other form of leakage detection is available.

The Required Actions are modified by a Note that states that the provisions of LCO 3.0.4 are not applicable. As a result, a MODE change is allowed when both the gaseous and particulate drywell continuous atmospheric monitoring systems are inoperable. This allowance is provided because other instrumentation is available to monitor RCS leakage.

(continued)

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RCS Leakage Detection Instrumentation B 3.4.5_

BASES ACTIONS D.1 and D.2 (continued)

If any Required Action and associated Completion Time of Condition A or B cannot be met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours0.5 days 0.0714 weeks 0.0164 months and MODE 4 within 36 hours1.5 days 0.214 weeks 0.0493 months . The allowed Completion Times are reasonable, based on operating experience, to perform the actions in an orderly manner and without challenging plant systems.

E.1 With all required monitors inoperable, no required automatic means of monitoring LEAKAGE are available, and immediate plant shutdown in accordance with LCO 3.0.3 is required.

SURVEILLANCE The Surveillances are modified by a Note to indicate that REQUIREMENTS when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours0.25 days 0.0357 weeks 0.00822 months , provided the other required instrumentation (the drywell floor drain sump monitoring system or drywell continuous atmospheric monitoring channel, as applicable) is OPERABLE. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. The 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance is acceptable since it does not significantly reduce the probability of properly monitoring RCS leakage.

SR 3.4.5.1 This SR is for the performance of a CHANNEL CHECK of the required drywell continuous atmospheric monitoring channels.

The check gives reasonable confidence that the channels are operating properly. The Frequency of 12 hours0.5 days 0.0714 weeks 0.0164 months is based on instrument reliability and is reasonable for detecting off normal conditions.

SR 3.4.5.2 This SR is for the performance of a CHANNEL FUNCTIONAL TEST of the required RCS leakage detection instrumentation. The test ensures that the monitors can perform their function in (continued)

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RCS Leakage Detection Instrumentation B 3.4.5_

BASES SURVEILLANCE SR 3.4.5.2 (continued)

REQUIREMENTS the desired manner. The test also verifies the alarm setpoint and relative accuracy of the instrument channel. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. The Frequency of 31 days considers instrument reliability, and operating experience has shown it proper for detecting degradation.

SR 3.4.5.3 This SR is for the performance of a CHANNEL CALIBRATION of required leakage detection instrumentation channels. The calibration verifies the accuracy of the instrument channel.

The Frequency is 92 days and operating experience has proven this Frequency is acceptable.

REFERENCES 1. UFSAR, Section 16.6.

2. UFSAR, Section 4.10.

3. UFSAR. Section 4.10.3.4.

4. UFSAR, Section 4.10.2.3.

5. JAF-CALC-PRM-03345, Rev. 0, March 2000.

6. UFSAR, Section 4.10.3.2.

7. UFSAR, Section 16.3.2.2.

8. 10 CFR 50.36(c)(2)(ii).

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RCS Specific Activity B 3.4.6-B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.6 RCS Specific Activity BASES BACKGROUND During circulation, the reactor coolant acquires radioactive materials due to release of fission products from fuel leaks into the reactor coolant and activation of corrosion products in the reactor coolant. These radioactive materials in the reactor coolant can plate out in the RCS, and, at times, an accumulation will break away to spike the normal level of radioactivity. The release of coolant during a Design Basis Accident (DBA) could send radioactive materials into the environment.

Limits on the maximum allowable level of radioactivity in the reactor coolant are established to ensure that in the event of a release of any radioactive material to the environment during a DBA, radiation doses are maintained within the limits of 10 CFR 100.11 (Ref. 1).

This LCO contains iodine specific activity limits. The iodine isotopic activities per gram of reactor coolant are expressed in terms of a DOSE EQUIVALENT 1-131. The allowable levels are intended to limit the 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months radiation dose to an individual at the site boundary to a small fraction of the 10 CFR 100 limit.

APPLICABLE Analytical methods and assumptions involving radioactive SAFETY ANALYSES material in the primary coolant are presented in the UFSAR (Ref. 2). The specific activity in the reactor coolant (the source term) is an initial condition for evaluation of the consequences of an accident due to a main steam line break (MSLB) outside containment. No fuel damage is postulated in the MSLB accident, and the release of radioactive material to the environment is assumed to end when the main steam isolation valves (MSIVs) close completely.

This MSLB release forms the basis for determining offsite and control room doses (Ref. 2). The limits on the specific activity of the primary coolant ensure that the 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months thyroid and whole body doses at the site boundary, resulting from an MSLB outside containment during steady state operation, will not exceed 10% of the dose guidelines of 10 CFR 100. The limits on the specific activity of the primary coolant also ensure the thyroid dose to the control room operators, resulting from an MSLB outside containment during steady state operation will not exceed the limits specified in GDC 19 of 10 CFR 50, Appendix A (Ref. 3).

(continued)

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RCS Specific Activity B 3.4.6_

BASES APPLICABLE The limits on specific activity are values from a parametric SAFETY ANALYSES evaluation of typical site locations. These limits are (continued) conservative because the evaluation considered more restrictive parameters than for a specific site, such as the location of the site boundary and the meteorological conditions of the site.

RCS specific activity satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii) (Ref. 4).

LCO The specific iodine activity is limited to

0.2 pCi/gm DOSE EQUIVALENT 1-131. This limit ensures the source term assumed in the safety analysis for the MSLB is not exceeded.

so any release of radioactivity to the environment during an MSLB is less than a small fraction of the 10 CFR 100 limits.

APPLICABILITY In MODE 1, and MODES 2 and 3 with any main steam line not isolated, limits on the primary coolant radioactivity are applicable since there is an escape path for release of radioactive material from the primary coolant to the environment in the event of an MSLB outside of primary containment.

In MODES 2 and 3 with the main steam lines isolated, such limits do not apply since an escape path does not exist. In MODES 4 and 5, no limits are required since the reactor is not pressurized and the potential for leakage is reduced.

ACTIONS A.1 and A.2 When the reactor coolant specific activity exceeds the LCO DOSE EQUIVALENT 1-131 limit, but is

2.0 pCi/gm, samples must be analyzed for DOSE EQUIVALENT 1-131 at least once every 4 hours0.167 days 0.0238 weeks 0.00548 months . In addition, the specific activity must be restored to the LCO limit within 48 hours2 days 0.286 weeks 0.0658 months . The Completion Time of once every 4 hours0.167 days 0.0238 weeks 0.00548 months is based on the time needed to take and analyze a sample. The 48 hour5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months Completion Time to restore the activity level provides a reasonable time for temporary coolant activity increases (iodine spikes or crud bursts) to be cleaned up with the normal processing systems.

A Note to the Required Actions of Condition A excludes the MODE change restriction of LCO 3.0.4. This exception allows entry into the applicable MODE(S) while relying on the ACTIONS even though the ACTIONS may eventually require plant shutdown. This exception is acceptable due to the (continued)

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RCS Specific Activity B 3.4.6 BASES ACTIONS A.1 and A.2 (continued) significant conservatism incorporated into the specific activity limit, the low probability of an event which is limiting due to exceeding this limit, and the ability to restore transient specific activity excursions while the plant remains at, or proceeds to power operation.

B.1, B.2.1, B.2.2.1, and B.2.2.2 If the DOSE EQUIVALENT 1-131 cannot be restored to

0.2 pCi/gm within 48 hours2 days 0.286 weeks 0.0658 months , or if at any time it is

> 2.0 pCi/gm, it must be determined at least once every 4 hours0.167 days 0.0238 weeks 0.00548 months and all the main steam lines must be isolated within 12 hours0.5 days 0.0714 weeks 0.0164 months . Isolating the main steam lines precludes the possibility of releasing radioactive material to the environment in an amount that is more than a small fraction of the requirements of 10 CFR 100.11 and GDC 19 of 10 CFR 50 Appendix A (Ref. 3) during a postulated MSLB accident.

Alternatively, the plant can be placed in MODE 3 within 12 hours0.5 days 0.0714 weeks 0.0164 months and in MODE 4 within 36 hours1.5 days 0.214 weeks 0.0493 months . This option is provided for those instances when isolation of main steam lines is not desired (e.g., due to the decay heat loads).

In MODE 4, the requirements of the LCO are no longer applicable.

The Completion Time of once every 4 hours0.167 days 0.0238 weeks 0.00548 months is the time needed to take and analyze a sample. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time is reasonable, based on operating experience, to isolate the main steam lines in an orderly manner and without challenging plant systems. Also, the allowed Completion Times for Required Actions B.2.2.1 and B.2.2.2 for placing the plant in MODES 3 and 4 are reasonable, based on operating experience, to achieve the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.4.6.1 REQUIREMENTS This Surveillance is performed to ensure iodine remains within limit during normal operation. The 7 day Frequency is adequate to trend changes in the iodine activity level.

This SR is modified by a Note that requires this Surveillance to be performed only in MODE 1 because the level of fission products generated in other MODES is much less.

(continued)

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RCS Specific Activity B 3.4.6-BASES (continued)

REFERENCES 1. 10 CFR 100.11.

2. UFSAR, Section 14.8.

3. 10 CFR 50, Appendix A, GDC 19.

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RHR Shutdown Cooling System-Hot Shutdown B 3.4.7 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.7 Residual Heat Removal (RHR) Shutdown Cooling System-Hot Shutdown BASES BACKGROUND Irradiated fuel in the shutdown reactor core generates heat during the decay of fission products and increases the temperature of the reactor coolant. This decay heat must be removed to reduce the temperature of the reactor coolant to

212°F in preparation for performing Refueling or Cold Shutdown maintenance operations, or the decay heat must be removed for maintaining the reactor in the Hot Shutdown condition.

The two redundant, manually controlled shutdown cooling subsystems (loops) of the RHR System provide decay heat removal. Each loop consists of two motor driven pumps, a heat exchanger, and associated piping and valves. Both loops have a common suction from the same reactor water recirculation loop. Each pump discharges the reactor coolant, after circulation through the respective heat exchanger, to the reactor via the associated reactor water recirculation loop. The RHR heat exchangers transfer heat to the RHR Service Water System (LCO 3.7.1, "Residual Heat Removal Service Water (RHRSW) System").

APPLICABLE Decay heat removal by operation of the RHR System in the SAFETY ANALYSES shutdown cooling mode is not required for mitigation of any event or accident evaluated in the safety analyses (Ref. 1).

Decay heat removal is, however, an important safety function that must be accomplished or core damage could result. The RHR shutdown cooling subsystem meets Criterion 4 of 10 CFR 50.36(c)(2)(ii) (Ref. 2).

LCO Two RHR shutdown cooling subsystems are required to be OPERABLE. An OPERABLE RHR shutdown cooling subsystem consists of one OPERABLE RHR pump, one heat exchanger, and the associated piping and valves. The two subsystems have a common suction source and are allowed to have a common heat exchanger and common discharge piping. Thus, to meet the LCO, both RHR pumps (and two RHR service water pumps) in one loop or one RHR pump (and one RHR service water pump) in each of the two loops must be OPERABLE. Since the piping and heat exchangers are passive components that are assumed not to fail, they are allowed to be common to both subsystems. Each shutdown cooling subsystem is considered OPERABLE if it can be manually aligned (from the control (continued)

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RHR Shutdown Cooling System-Hot Shutdown B 3.4.7-BASES LCO room or locally) in the shutdown cooling mode for removal of (continued) decay heat. In MODE 3, one RHR shutdown cooling subsystem can provide the required cooling, but two subsystems are required to be OPERABLE to provide redundancy. Operation of one subsystem can maintain or reduce the reactor coolant temperature as required. However, to ensure adequate core flow to allow for accurate average reactor coolant temperature monitoring, nearly continuous operation is required.

The Note allows one RHR shutdown cooling subsystem to be inoperable for up to 2 hours0.0833 days 0.0119 weeks 0.00274 months for the performance of Surveillance tests. These tests may be on the affected RHR System or on some other plant system or component that necessitates placing the RHR shutdown cooling subsystem in an inoperable status during the performance. This is permitted because the core heat generation can be low enough and the heatup rate slow enough to allow some changes to the RHR shutdown cooling subsystems or other operations requiring loss of redundancy.

APPLICABILITY In MODE 3 with reactor steam dome pressure below the RHR cut-in permissive pressure (i.e., the actual pressure at which the shutdown cooling suction valve isolation logic interlock resets (Function 6.a of LCO 3.3.6.1, "Primary Containment Isolation Instrumentation")) the RHR System is required to be OPERABLE so that it may be operated in the shutdown cooling mode to remove decay heat to reduce or maintain coolant temperature. Otherwise, a recirculation pump is normally in operation to circulate coolant to provide for temperature monitoring.

In MODES 1 and 2, and in MODE 3 with reactor steam dome pressure greater than or equal to the RHR cut-in permissive pressure, this LCO is not applicable. Operation of the RHR System in the shutdown cooling mode is not allowed above this pressure because the RCS pressure may exceed the design pressure of the shutdown cooling piping. Decay heat removal at reactor pressures greater than or equal to the RHR cut in permissive pressure is typically accomplished by condensing the steam in the main condenser. Additionally, in MODE 2 below this pressure, the OPERABILITY requirements for the Emergency Core Cooling Systems (ECCS) (LCO 3.5.1, "ECCS-Operating") do not allow placing the RHR shutdown cooling subsystem into operation.

(continued)

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RHR Shutdown Cooling System-Hot Shutdown B 3.4.7_

BASES APPLICABILITY The requirements for decay heat removal in MODES 4 and 5 are (continued) discussed in LCO 3.4.8, "Residual Heat Removal (RHR)

Shutdown Cooling System-Cold Shutdown": LCO 3.9.7, "Residual Heat Removal (RHR)-High Water Level"; and LCO 3.9.8, "Residual Heat Removal (RHR)-Low Water Level."

ACTIONS A Note to the ACTIONS excludes the MODE change restriction of LCO 3.0.4. This exception allows entry into the applicable MODE(S) while relying on the ACTIONS even though the ACTIONS may eventually require plant shutdown. This exception is acceptable due to the redundancy of the OPERABLE subsystems, the low pressure at which the plant is operating, the low probability of an event occurring during operation in this condition, and the availability of alternate methods of decay heat removal capability.

A second Note has been provided to modify the ACTIONS related to RHR shutdown cooling subsystems. Section 1.3, Completion Times, specifies once a Condition has been entered, subsequent divisions, subsystems, components or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable shutdown cooling subsystems provide appropriate compensatory measures for separate inoperable shutdown cooling subsystems. As such, a Note has been provided that allows separate Condition entry for each inoperable RHR shutdown cooling subsystem.

A.1, A.2, and A.3 With one required RHR shutdown cooling subsystem inoperable for decay heat removal, except as permitted by the LCO Note, the inoperable subsystem must be restored to OPERABLE status without delay. In this condition, the remaining OPERABLE subsystem can provide the necessary decay heat removal. The overall reliability is reduced, however, because a single failure in the OPERABLE subsystem could result in reduced RHR shutdown cooling capability. Therefore, an alternate method of decay heat removal must be provided.

With both RHR shutdown cooling subsystems inoperable, an alternate method of decay heat removal must be provided in addition to that provided for the initial RHR shutdown (continued)

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RHR Shutdown Cooling System-Hot Shutdown B 3.4.7 BASES ACTIONS A.1, A.2, and A.3 (continued) cooling subsystem inoperability. This re-establishes backup decay heat removal capabilities, similar to the requirements of the LCO. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is based on the decay heat removal function and the probability of a loss of the available decay heat removal capabilities.

The required cooling capacity of the alternate method should be ensured by verifying (by calculation or demonstration) its capability to maintain or reduce temperature. Decay heat removal by ambient losses can be considered as, or contributing to, the alternate method capability. Alternate methods that can be used include (but are not limited to) the Condensate and Main Steam Systems, Reactor Water Cleanup System (by itself or using feed and bleed in combination with the Control Rod Drive System or Condensate System), or a combination of an RHR pump and safety/relief valve(s).

However, due to the potentially reduced reliability of the alternate methods of decay heat removal, it is also required to reduce the reactor coolant temperature to the point where MODE 4 is entered.

SURVEILLANCE SR 3.4.7.1 REQUIREMENTS Verifying the correct alignment for manual, power operated, and automatic valves in the RHR shutdown cooling flow path provides assurance that the proper flow paths will exist for RHR operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these were verified to be in the correct position prior to locking, sealing, or securing. A valve that can be manually (from the control room or locally) aligned is allowed to be in a non-RHR shutdown cooling position provided the valve can be repositioned. This SR does not require any testing or valve manipulation: rather, it involves verification that those valves capable of potentially being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.

The 31 day Frequency of this SR was derived from the Inservice Testing Program requirements for performing valve testing at least once every 92 days. The Frequency of 31 days is further justified because the valves are operated under procedural control. This Frequency has been shown to be acceptable through operating experience.

(continued)

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RHR Shutdown Cooling System-Hot Shutdown B 3.4.7_

BASES SURVEILLANCE SR 3.4.7.1 (continued)

REQUIREMENTS This Surveillance is modified by a Note allowing sufficient time to verify RHR shutdown cooling subsystem OPERABILITY after clearing the pressure interlock that isolates the system. The Note takes exception to the requirements of the Surveillance being met (i.e., valves are aligned or can be aligned is not required for this initial 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months period),

which also allows entry into the Applicability of this Specification in accordance with SR 3.0.4 since the Surveillance will not be "not met" at the time of entry into the Applicability.

REFERENCES 1. UFSAR, Chapter 14.

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RHR Shutdown Cooling System-Cold Shutdown B 3.4.8 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.8 Residual Heat Removal (RHR) Shutdown Cooling System-Cold Shutdown BASES BACKGROUND Irradiated fuel in the shutdown reactor core generates heat during the decay of fission products and increases the temperature of the reactor coolant. This decay heat must be removed to maintain the temperature of the reactor coolant

212°F in preparation for performing refueling operations, or the decay heat must be removed for maintaining the reactor in the Cold Shutdown condition.

The two redundant, manually controlled shutdown cooling subsystems (loops) of the RHR System provide decay heat removal. Each loop consists of two motor driven pumps, a heat exchanger, and associated piping and valves. Both loops have a common suction from the same reactor water recirculation loop. Each pump discharges the reactor coolant, after circulation through the respective heat exchanger, to the reactor via a reactor water recirculation loop. The RHR heat exchangers transfer heat to the RHR Service Water System.

APPLICABLE Decay heat removal by operation of the RHR System in the SAFETY ANALYSES shutdown cooling mode is not required for mitigation of any event or accident evaluated in the safety analyses (Ref. 1).

Decay heat removal is, however, an important safety function that must be accomplished or core damage could result. The RHR Shutdown Cooling System meets Criterion 4 of 10 CFR 50.36(c)(2)(ii) (Ref. 2).

LCO Two RHR shutdown cooling subsystems are required to be OPERABLE. An OPERABLE RHR shutdown cooling subsystem consists of one OPERABLE RHR pump, one heat exchanger, one or two RHR service water pumps providing water to the heat exchanger, as required for temperature control, and the associated piping and valves. The two subsystems have a common suction source and are allowed to have a common heat exchanger and common discharge piping. Thus, to meet the LCO, both RHR pumps (and two RHR service water pumps) in one loop or one RHR pump (and one RHR service water pump) in each of the two loops must be OPERABLE. Since the piping and heat exchangers are passive components that are assumed not to fail, they are allowed to be common to both subsystems. In MODE 4, the RHR cross tie valves (1OMOV-20 and 1ORHR-09) may be opened to allow pumps in one loop to (continued)

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RHR Shutdown Cooling System-Cold Shutdown B 3.4.8_

BASES LCO discharge through the opposite recirculation loop to make a (continued) complete subsystem. Additionally, each shutdown cooling subsystem is considered OPERABLE if it can be manually aligned (from the control room or locally) in the shutdown cooling mode for removal of decay heat. In MODE 4, one RHR shutdown cooling subsystem can provide the required cooling, but two subsystems are required to be OPERABLE to provide redundancy. Operation of one subsystem can maintain or reduce the reactor coolant temperature as required.

However, to ensure adequate core flow to allow for accurate average reactor coolant temperature monitoring, nearly continuous operation is required.

The Note allows one RHR shutdown cooling subsystem to be inoperable for up to 2 hours0.0833 days 0.0119 weeks 0.00274 months for the performance of Surveillance tests. These tests may be on the affected RHR System or on some other plant system or component that necessitates placing the RHR shutdown cooling subsystems in an inoperable status during the performance. This is permitted because the core heat generation can be low enough and the heatup rate slow enough to allow some changes to the RHR shutdown cooling subsystems or other operations requiring loss of redundancy.

APPLICABILITY In MODE 4, the RHR System is required to be OPERABLE so that it may be operated in the shutdown cooling mode to remove decay heat to maintain coolant temperature below 212 0 F.

Otherwise, a recirculation pump is normally in operation to circulate coolant to provide for temperature monitoring.

In MODES 1 and 2, and in MODE 3 with reactor steam dome pressure greater than or equal to the RHR cut in permissive pressure, this LCO is not applicable. Operation of the RHR System in the shutdown cooling mode is not allowed above this pressure because the RCS pressure may exceed the design pressure of the shutdown cooling piping. Decay heat removal at reactor pressures greater than or equal to the RHR cut in permissive pressure is typically accomplished by condensing the steam in the main condenser. Additionally, in MODE 2 below this pressure, the OPERABILITY requirements for the Emergency Core Cooling Systems (ECCS) (LCO 3.5.1, "ECCS-Operating") do not allow placing the RHR shutdown cooling subsystem into operation.

The requirements for decay heat removal in MODE 3 below the cut in permissive pressure and in MODE 5 are discussed in LCO 3.4.7, "Residual Heat Removal (RHR) Shutdown Cooling (continued)

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RHR Shutdown Cooling System-Cold Shutdown B 3.4.8 BASES APPLICABILITY System-Hot Shutdown", LCO 3.9.7, "Residual Heat Removal (continued) (RHR)-High Water Level"; and LCO 3.9.8, "Residual Heat Removal (RHR) -Low Water Level."

ACTIONS A Note has been provided to modify the ACTIONS related to RHR shutdown cooling subsystems. Section 1.3, Completion Times, specifies once a Condition has been entered, subsequent divisions, subsystems, components or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable shutdown cooling subsystems provide appropriate compensatory measures for separate inoperable shutdown cooling subsystems. As such, a Note has been provided that allows separate Condition entry for each inoperable RHR shutdown cooling subsystem.

A.1 With one of the two required RHR shutdown cooling subsystems inoperable, except as permitted by the LCO Note, the remaining subsystem is capable of providing the required decay heat removal. However, the overall reliability is reduced. Therefore, an alternate method of decay heat removal must be provided. With both RHR shutdown cooling subsystems inoperable, an alternate method of decay heat removal must be provided in addition to that provided for the initial RHR shutdown cooling subsystem inoperability.

This re-establishes backup decay heat removal capabilities, similar to the requirements of the LCO. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is based on the decay heat removal function and the probability of a loss of the available decay heat removal capabilities. Furthermore, verification of the functional availability of these alternate method(s) must be reconfirmed every 24 hours1 days 0.143 weeks 0.0329 months thereafter. This will provide assurance of continued heat removal capability.

The required cooling capacity of the alternate method should be ensured by verifying (by calculation or demonstration) its capability to maintain or reduce temperature. Decay heat removal by ambient losses can be considered as, or contributing to, the alternate method capability. Alternate methods that can be used include (but are not limited to)

(continued)

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RHR Shutdown Cooling System-Cold Shutdown B 3.4.8-BASES ACTIONS A.1 (continued) the Condensate and Main Steam Systems, Reactor Water Cleanup System (by itself or using feed and bleed in combination with the Control Rod Drive System or Condensate System), or a combination of an RHR pump and safety/relief valve(s).

SURVEILLANCE SR 3.4.8.1 REQUIREMENTS Verifying the correct alignment for manual, power operated, and automatic valves in the RHR shutdown cooling flow path provides assurance that the proper flow paths will exist for RHR operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these were verified to be in the correct position prior to locking, sealing, or securing. A valve that can be manually (from the control room or locally) aligned is allowed to be in a non-RHR shutdown cooling position provided the valve can be repositioned. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of potentially being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.

The 31 day Frequency of this SR was derived from the Inservice Testing Program requirements for performing valve testing at least once every 92 days. The Frequency of 31 days is further justified because the valves are operated under procedural control. This Frequency has been shown to be acceptable through operating experience.

REFERENCES 1. UFSAR, Chapter 14.

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RCS P/T Limits B 3.4.9_

B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.9 RCS Pressure and Temperature (P/T) Limits BASES BACKGROUND All components of the RCS are designed to withstand effects of cyclic loads due to system pressure and temperature changes. These loads are introduced by startup (heatup) and shutdown (cooldown) operations, power transients, and reactor trips. This LCO limits the pressure and temperature changes during RCS heatup and cooldown, within the design assumptions and the stress limits for cyclic operation.

This Specification contains P/T limit curves for heatup, cooldown, inservice leakage and hydrostatic testing, and criticality and also limits the maximum rate of change of reactor coolant temperature.

Each P/T limit curve defines an acceptable region for normal operation. The curves are used for operational guidance during heatup or cooldown maneuvering. Pressure and temperature are monitored and compared to the applicable curve to ensure that operation is within the allowable region.

The LCO establishes operating limits that provide a margin to brittle failure of the reactor vessel and piping of the reactor coolant pressure boundary (RCPB). The vessel is the component most subject to brittle failure. Therefore, the LCO limits apply mainly to the vessel.

10 CFR 50, Appendix G (Ref. 1), requires the establishment of P/T limits for material fracture toughness requirements of the RCPB materials. Reference 1 requires an adequate margin to brittle failure during normal operation, abnormal operational transients, and system inservice leakage and hydrostatic tests. It mandates the use of the ASME Code,Section III, Appendix G (Ref. 2).

The nil-ductility transition (NDT) temperature, RTNDT, is defined as the temperature below which ferritic steel breaks in a brittle rather than ductile manner. The RTNDT increases as a function of neutron exposure at integrated neutron exposures greater than approximately 1017 nvt with neutron energy in excess of 1 MeV.

The actual shift in the RTNDT of the vessel material is determined periodically by removing and evaluating the irradiated reactor vessel material specimens, in accordance (continued)

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RCS P/T Limits B 3.4.9_

BASES BACKGROUND with ASTM E 185 (Ref. 3) and Appendix H of 10 CFR 50 (continued) (Ref. 4). The operating P/T limit curves are adjusted, as necessary, based on the evaluation findings and the recommendations of Reference 5.

The P/T limit curves are composite curves established by superimposing limits derived from stress analyses of those portions of the reactor vessel and head that are the most restrictive. At any specific pressure, temperature, and temperature rate of change, one location within the reactor vessel will dictate the most restrictive limit. Across the span of the P/T limit curves, different locations are more restrictive, and, thus, the curves are composites of the most restrictive locations.

The heatup curve represents a different set of restrictions than the cooldown curve because the directions of the thermal gradients through the vessel wall are reversed. The thermal gradient reversal alters the location of the tensile stress between the outer and inner walls. However, the P/T limit curves reflect the most restrictive of the heatup and cooldown curves.

The P/T criticality limits include the Reference 1 requirement that they be at least 40°F above the heatup curve or the cooldown curve and not lower than the minimum permissible temperature for the inservice leakage and hydrostatic testing.

The consequence of violating the LCO limits is that the RCS has been operated under conditions that can result in brittle failure of the RCPB, possibly leading to a nonisolable leak or loss of coolant accident. In the event these limits are exceeded, an evaluation must be performed to determine the effect on the structural integrity of the RCPB components. ASME Code,Section XI, Appendix E (Ref. 6), provides a recommended methodology for evaluating an operating event that causes an excursion outside the limits.

APPLICABLE The P/T limits are not derived from Design Basis Accident SAFETY ANALYSES (DBA) analyses. They are prescribed during normal operation to avoid encountering pressure, temperature, and temperature rate of change conditions that might cause undetected flaws to propagate and cause nonductile failure of the RCPB, a condition that is unanalyzed. Reference 7 establishes the methodology for determining the P/T limits. Reference 8 (continued)

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RCS P/T Limits B 3.4.9 BASES APPLICABLE approved the curves and limits required by this SAFETY ANALYSES Specification. Since the P/T limits are not derived from (continued) any DBA, there are no acceptance limits related to the P/T limits. Rather, the P/T limits are acceptance limits themselves since they preclude operation in an unanalyzed condition.

RCS P/T limits satisfy Criterion 2 of 10 CFR 50.36(c)(2)(ii)

(Ref. 9).

LCO The elements of this LCO are:

a. RCS pressure and temperature are within the limits specified in Figure 3.4.9-1 or Figure 3.4.9-2, as applicable. In addition, RCS temperature change averaged over a one hour period is: : 100'F when the RCS pressure and temperature are on or to the right of curve C of Figure 3.4.9-1 or Figure 3.4.9-2, as applicable, during inservice leak and hydrostatic testing; - 20°F when the RCS pressure and temperature are to the left of curve C of Figure 3.4.9-1 or Figure 3.4.9-2, as applicable, during inservice leak and hydrostatic testing; and : 1007F during other heatup and cooldown operations;

b. The temperature difference between the reactor vessel bottom head coolant and the reactor pressure vessel (RPV) coolant is

145 0 F during recirculation pump startup;

c. The temperature difference between the reactor coolant in the respective recirculation loop and in the reactor vessel is < 50°F during recirculation pump startup;

d. RCS pressure and temperature are within the limits specified in Figure 3.4.9-1 or Figure 3.4.9-2, as applicable, prior to achieving criticality; and

e. The reactor vessel flange and the head flange temperatures are 2 90°F when tensioning the reactor vessel head bolting studs and when any stud is tensioned.

These limits define allowable operating regions and permit a large number of operating cycles while also providing a wide margin to nonductile failure.

(continued)

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RCS P/T Limits B 3.4.9.

BASES LCO The limits on the rate of change of RCS temperature, (continued) influenced by RCS flow and RCS stratification, control the thermal gradient through the vessel wall. For this reason, both RCS temperature and RPV metal temperatures are used as inputs for calculating the heatup, cooldown, and inservice leakage and hydrostatic testing P/T limit curves. Thus, the LCO for the rate of change of temperature restricts stresses caused by thermal gradients and also ensures the validity of the P/T limit curves.

P/T limit curves are provided for plant operations through 24 EFPY (Figure 3.4.9-1) and 32 EFPY (Figure 3.4.9-2).

Curves A, ABH (bottom head), and ANB (non-beltline) establish the minimum temperature for hydrostatic and leak testing, Curves B and BH (bottom head) establish limits for plant heatup and cooldown when the reactor is not critical or during low power physics tests, and Curve C establishes the limits when the reactor is critical. In addition, ART is the adjusted reference temperature.

Violation of the limits places the reactor vessel outside of the bounds of the stress analyses and can increase stresses in other RCS components. The consequences depend on several factors, as follows:

a. The severity of the departure from the allowable operating pressure temperature regime or the severity of the rate of change of temperature:

b. The length of time the limits were violated (longer violations allow the temperature gradient in the thick vessel walls to become more pronounced); and

c. The existence, size, and orientation of flaws in the vessel material.

APPLICABILITY The potential for violating a P/T limit exists at all times.

For example, P/T limit violations could result from ambient temperature conditions that result in the reactor vessel metal temperature being less than the minimum allowed temperature for boltup. Therefore, this LCO is applicable even when fuel is not loaded in the core.

(continued)

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RCS P/T Limits B 3.4.9_

BASES (continued)

ACTIONS A.1 and A.2 Operation outside the P/T limits while in MODE 1. 2, or 3 must be corrected so that the RCPB is returned to a condition that has been verified by stress analyses.

The 30 minute Completion Time reflects the urgency of restoring the parameters to within the analyzed range. Most violations will not be severe, and the activity can be accomplished in this time in a controlled manner.

Besides restoring the P/T limit parameters to within limits, an evaluation is required to determine if RCS operation can continue. This evaluation must verify the RCPB integrity remains acceptable and must be completed if continued operation is desired. Several methods may be used, including comparison with pre-analyzed transients in the stress analyses, new analyses, or inspection of the components. ASME Code,Section XI, Appendix E (Ref. 6), may be used to support the evaluation. However, its use is restricted to evaluation of the vessel beltline.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is reasonable to accomplish the engineering evaluation of a mild violation. A mild violation is one which is technically acceptable because it is bounded by an existing evaluation or one which reasonably can be expected to be found acceptable following evaluation.

More severe violations may require special, event specific stress analyses or inspections. A favorable evaluation must be completed if continued operation is desired.

Condition A is modified by a Note requiring Required Action A.2 be completed whenever the Condition is entered.

The Note emphasizes the need to perform the evaluation of the effects of the excursion outside the allowable limits.

Restoration alone per Required Action A.1 is insufficient because higher than analyzed stresses may have occurred and may have affected the RCPB integrity.

B.1 and B.2 If a Required Action and associated Completion Time of Condition A are not met, the plant must be placed in a lower MODE because either the RCS remained in an unacceptable P/T region for an extended period of increased stress, or a sufficiently severe event caused entry into an unacceptable region. Either occurrence indicates a need for more careful examination of the event, best accomplished with the RCS at (continued)

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RCS P/T Limits B 3.4.9 BASES ACTIONS B.1 and B.2 (continued) reduced pressure and temperature. With the reduced pressure and temperature conditions, the likelihood of propagation of undetected flaws is decreased.

Pressure and temperature are reduced by placing the plant in at least MODE 3 within 12 hours0.5 days 0.0714 weeks 0.0164 months and in MODE 4 within 36 hours1.5 days 0.214 weeks 0.0493 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

C.1 and C.2 Operation outside the P/T limits in other than MODES 1, 2, and 3 (including defueled conditions) must be corrected so that the RCPB is returned to a condition that has been verified by stress analyses. The Required Action must be initiated without delay and continued until the limits are restored.

Besides restoring the P/T limit parameters to within limits, an evaluation is required to determine if RCS operation is allowed. This evaluation must verify that the RCPB integrity is acceptable and must be completed before approaching criticality or heating up to > 212 0 F. Several methods may be used, including comparison with pre-analyzed transients, new analyses, or inspection of the components.

ASME Code,Section XI, Appendix E (Ref. 6), may be used to support the evaluation; however, its use is restricted to evaluation of the beltline.

Condition C is modified by a Note requiring Required Action C.2 to be completed whenever the Condition is entered. The Note emphasizes the need to perform the evaluation of the effects of the excursion outside the allowable limits. Restoration alone per Required Action C.1 is insufficient because higher than analyzed stresses may have occurred and may have affected the RCPB integrity.

SURVEILLANCE SR 3.4.9.1 REQUIREMENTS Verification that operation is within RCS pressure and temperature limits as well as within RCS temperature change limits is required every 30 minutes when RCS pressure and temperature conditions are undergoing planned changes. This (continued)

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RCS P/T Limits B 3.4.9_

BASES SURVEILLANCE SR 3.4.9.1 (continued)

REQUIREMENTS is accomplished by monitoring the bottom head drain, recirculation loop, and RPV metal temperatures. This Frequency is considered reasonable in view of the control room indication available to monitor RCS status. Also, since temperature rate of change limits are specified in hourly increments, 30 minutes permits a reasonable time for assessment and correction of minor deviations. The limits of Figures 3.4.9-1 and 3.4.9-2 are met when operation is on or to the right of the applicable curve.

Surveillance for heatup, cooldown, or inservice leakage and hydrostatic testing may be discontinued when the criteria given in the relevant plant procedure for ending the activity are satisfied. In general, if two consecutive temperature readings taken Ž 30 minutes apart are within 50 F of each other the activity can be considered complete.

This SR is modified by a Note that requires this Surveillance to be performed only during system heatup and cooldown operations and inservice leakage and hydrostatic testing. Unlike steady-state operation, these intentional operational transients may be characterized by large pressure and temperature changes, and performance of this SR provides assurance that RCS pressure and temperature remain within acceptable regions of the P/T limit curves as well as within RCS temperature change limits.

SR 3.4.9.2 A separate limit is used when the reactor is approaching criticality. Consequently, the RCS pressure and temperature must be verified within the appropriate limits before withdrawing control rods that will make the reactor critical.

Performing the Surveillance within 15 minutes before control rod withdrawal for the purpose of achieving criticality provides adequate assurance that the limits will not be exceeded between the time of the Surveillance and the time of the control rod withdrawal.

SR 3.4.9.3, SR 3.4.9.4, and SR 3.4.9.5 Differential temperatures within the specified limits ensure that thermal stresses resulting from the startup of an idle recirculation pump will not exceed design allowances. In (continued)

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RCS P/T Limits B 3.4.9 BASES SURVEILLANCE SR 3.4.9.3, SR 3.4.9.4, and SR 3.4.9.5 (continued)

REQUIREMENTS addition, compliance with these limits ensures that the assumptions of the analysis for the startup of an idle recirculation loop (Ref. 10) are satisfied.

Performing the Surveillance within 15 minutes before starting the idle recirculation pump provides adequate assurance that the limits will not be exceeded between the time of the Surveillance and the time of the idle pump start.

Compliance with the temperature differential requirement in SR 3.4.9.3 is demonstrated by comparing the bottom head drain line temperature to the reactor vessel steam dome saturation temperature. SR 3.4.9.4 requires the verification that the active recirculation pump flow exceeds 40% of rated pump flow or the active recirculation pump has been operating below 40% rated flow for a period no longer than 30 minutes. As specified in Reference 11 and 12. the alternative verification of SR 3.4.9.4 will ensure the temperature differential of SR 3.4.9.3 is met.

An acceptable means of demonstrating compliance with the temperature differential requirement in SR 3.4.9.5 is to compare the temperatures of the operating recirculation loop and the idle loop.

SR 3.4.9.3, SR 3.4.9.4, and SR 3.4.9.5 have been modified by a Note that requires the Surveillance to be met only in MODES 1, 2, 3, and 4 during a recirculation pump startup since this is when the stresses occur. In MODE 5, the overall stress on limiting components is lower. Therefore, AT limits are not required. SR 3.4.9.3 is modified by a second Note, which clarifies that the SR does not have to be performed if SR 3.4.9.4 is satisfied. This is acceptable since References 11 and 12 demonstrate that SR 3.4.9.4 is an acceptable alternative. In addition, SR 3.4.9.4 is modified by a second Note, which clarifies that the SR does not have to be met if SR 3.4.9.3 is satisfied. This is acceptable since SR 3.4.9.3 directly verifies the stratification limit is met.

SR 3.4.9.6, SR 3.4.9.7, and SR 3.4.9.8 Limits on the reactor vessel flange and head flange temperatures are generally bounded by the other P/T limits during system heatup and cooldown. However, operations when any reactor vessel head bolting stud is tensioned with RCS (continued)

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RCS P/T Limits B 3.4.9 BASES SURVEILLANCE SR 3.4.9.6, SR 3.4.9.7, and SR 3.4.9.8 (continued)

REQUIREMENTS temperature less than or equal to certain specified values require assurance that these temperatures meet the LCO limits.

The flange temperatures must be verified to be above the limits within 30 minutes before and while tensioning the reactor vessel head bolting studs to ensure that once the head is tensioned the limits are satisfied. When any reactor vessel head bolting stud is tensioned with RCS temperature

100'F, 30 minute checks of the flange temperatures are required because of the reduced margin to the limits. When any reactor vessel head bolting stud is tensioned with RCS temperature

120 0 F, monitoring of the flange temperature is required every 12 hours0.5 days 0.0714 weeks 0.0164 months to ensure the temperature is within specified limits.

The 30 minute Frequency reflects the urgency of maintaining the temperatures within limits, and also limits the time that the temperature limits could be exceeded. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is reasonable based on the rate of temperature change possible at these temperatures.

SR 3.4.9.6 is modified by a Note which requires the SR to be performed only when tensioning the reactor vessel head bolting studs. SR 3.4.9.7 is modified by a Note which states that the SR is not required to be performed until 30 minutes after RCS temperature is - 100'F in MODE 4.

SR 3.4.9.8 is modified by a Note which states that the SR is not required to be performed until 12 hours0.5 days 0.0714 weeks 0.0164 months after RCS temperature is g 120°F in MODE 4. These Notes are necessary to specify when the reactor vessel flange and head flange temperatures are required to be within specified limits.

REFERENCES 1. 10 CFR 50, Appendix G.

2. ASME, Boiler and Pressure Vessel Code,Section III, Appendix G.

3. ASTM E 185-82, July 1982.

4. 10 CFR 50, Appendix H.

5. Regulatory Guide 1.99, Revision 2, Radiation Embrittlement of Reactor Vessel Materials, May 1988.

6. ASME, Boiler and Pressure Vessel Code,Section XI, Appendix E.

(continued)

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RCS P/T Limits B 3.4.9_

BASES REFERENCES 7. GE-NE-B1100732-01, Revision 1, Plant FitzPatrick RPV (continued) Surveillance Materials Testing and Analysis of 1200 Capsule at 13.4 EFPY, February 1998, including Errata and Addenda Sheets dated June 17, 1999 and December 3, 1999.

8. Letter from Guy Vissing (NRC) to James Knubel (NYPA)

Issuance of Amendment No. 258 to James A. FitzPatrick Nuclear Power Plant, November 29, 1999.

9. 10 CFR 50.36(c)(2)(ii).

10. UFSAR, Section 14.5.7.2.

11. GE-NE-208-04-1292, Evaluation of Idle Recirculation Loop Restart Without Vessel Bottom Temperature Indication for FitzPatrick Nuclear Power Plant, December 1992.

12. JAF-RPT-RWR-02076, Verification of Alternative Operating Conditions for Idle Recirculation Loop Restart Without Vessel Bottom Temperature Indication, June 25, 1995.

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ECCS- Operating B 3.5.1L B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM B 3.5.1 ECCS-Operating BASES BACKGROUND The ECCS is designed, in conjunction with the primary and secondary containment, to limit the release of radioactive materials to the environment following a loss of coolant accident (LOCA). The ECCS uses two independent methods (flooding and spraying) to cool the core during a LOCA. The ECCS network consists of the High Pressure Coolant Injection (HPCI) System, the Core Spray (CS) System, the low pressure coolant injection (LPCI) mode of the Residual Heat Removal (RHR) System, and the Automatic Depressurization System (ADS). The suppression pool provides the required source of water for the ECCS. Although no credit is taken in the safety analyses for the condensate storage tanks (CSTs),

they are capable of providing a source of water for the HPCI and CS systems.

On receipt of an initiation signal, ECCS pumps automatically start; simultaneously, the system aligns and the pumps inject water, taken either from the CSTs or suppression pool, into the Reactor Coolant System (RCS) as RCS pressure is overcome by the discharge pressure of the ECCS pumps.

Although the system is initiated, ADS action is delayed, allowing the operator to interrupt the timed sequence if the system is not needed. The HPCI pump discharge pressure almost immediately exceeds that of the RCS, and the pump injects coolant into the vessel to cool the core. If the break is small, the HPCI System will maintain coolant inventory as well as vessel level while the RCS is still pressurized. If HPCI fails, it is backed up by ADS in combination with LPCI and CS. In this event, if the ADS timed sequence is allowed to time out, the selected safety/relief valves (S/RVs) would open, depressurizing the RCS, thus allowing the LPCI and CS to overcome RCS pressure and inject coolant into the vessel. If the break is large, RCS pressure initially drops rapidly and the LPCI and CS cool the core.

Water from the break returns to the suppression pool where it is used again and again. Water in the suppression pool is circulated through a heat exchanger cooled by the RHR Service Water System. Depending on the location and size of the break, portions of the ECCS may be ineffective: however, the overall design is effective in cooling the core regardless of the size or location of the piping break.

(continued)

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ECCS- Operating B 3.5.1 BASES BACKGROUND All low pressure ECCS subsystems are designed to ensure that (continued) no single active component failure will prevent automatic initiation and successful operation of the minimum required ECCS equipment.

The CS System (Ref. 1) is composed of two independent subsystems. Each subsystem consists of a motor driven pump, a spray sparger above the core, and piping and valves to transfer water from the suppression pool to the sparger.

The CS System is designed to provide cooling to the reactor core when reactor pressure is low. Upon receipt of an initiation signal if preferred power is available, the CS pumps in both subsystems will automatically start after a time delay of approximately 11 seconds. If a CS initiation signal is received when preferred power is not available, the CS pumps start approximately 11 seconds after the associated bus is energized by the emergency diesel generators (EDGs). When the RPV pressure drops sufficiently, CS System flow to the RPV begins. A full flow test line is provided to route water to the suppression pool to allow testing of the CS System without spraying water in the RPV.

LPCI is an independent operating mode of the RHR System.

There are two LPCI subsystems (Ref. 2), each consisting of two motor driven pumps and piping and valves to transfer water from the suppression pool to the RPV via the corresponding recirculation loop. The two LPCI subsystems can be interconnected via the RHR System cross tie line; however, this line is maintained closed to prevent loss of both LPCI subsystems during a LOCA. The line is isolated by chain-locking the 1OMOV-20 valve in the closed position with electric power disconnected from its motor operator, and maintaining the manually operated gate valve (1ORHR-09) locked in the closed position. The LPCI subsystems are designed to provide core cooling at low RPV pressure. Upon receipt of an initiation signal if preferred power is available, LPCI pumps A and D start in approximately one second. LPCI pumps B and C are started in approximately 6 seconds to limit the loading of the preferred power sources.

With a loss of preferred power LPCI pumps A and D start in approximately one second after the associated bus is energized by the EDGs, and LPCI pumps B and C start approximately 6 seconds after the associated bus is energized by the EDGs to limit the loading of the EDGs. If one EDG should fail to force parallel, an associated LPCI pump will not start (LPCI pump B or C) to ensure the other EDG in the same EDG subsystem is not overloaded. RHR System (continued)

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ECCS- Operating B 3.5.L BASES BACKGROUND valves in the LPCI flow path are automatically positioned to (continued) ensure the proper flow path for water from the suppression pool to inject into the recirculation loops. When the RPV pressure drops sufficiently, the LPCI flow to the RPV, via the corresponding recirculation loop, begins. The water then enters the reactor through the jet pumps. A full flow test line is provided for each LPCI subsystem to route water from the suppression pool, to allow testing of the LPCI pumps without injecting water into the RPV. These test lines also provide suppression pool cooling capability, as described in LCO 3.6.2.3, "RHR Suppression Pool Cooling."

The HPCI System (Ref. 3) consists of a steam driven turbine pump unit, piping, and valves to provide steam to the turbine, as well as piping and valves to transfer water from the suction source to the core via the feedwater system line, where the coolant is distributed within the RPV through the feedwater sparger. Suction piping for the system is provided from both CSTs and the suppression pool.

Pump suction for HPCI is normally aligned to both CSTs to minimize injection of suppression pool water into the RPV.

However, if the water supply is low in both CSTs, or if the suppression pool level is high, an automatic transfer to the suppression pool water source ensures a water supply for continuous operation of the HPCI System and ensures the containment loads do not exceed design values. The steam supply to the HPCI turbine is piped from the "C" main steam line upstream of the inboard main steam isolation valve.

The HPCI System is designed to provide core cooling for a wide range of reactor pressures (150 psig to 1195 psig).

Upon receipt of an initiation signal, the HPCI turbine stop valve and turbine control valve open simultaneously and the turbine accelerates to a specified speed. As the HPCI flow increases, the turbine governor valve is automatically adjusted to maintain design flow. Exhaust steam from the HPCI turbine is discharged to the suppression pool. A full flow test line is provided to route water to the CSTs to allow testing of the HPCI System during normal operation without injecting water into the RPV.

The ECCS pumps are provided with minimum flow bypass lines, which discharge to the suppression pool. The valve in the HPCI line automatically opens to prevent pump damage due to overheating when other discharge line valves are closed.

The minimum flow bypass valves for the LPCI and CS pumps are normally open for the same purpose. To ensure rapid delivery of water to the RPV and to minimize water hammer (continued)

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ECCS- Operating B 3.5. L BASES BACKGROUND effects, all ECCS pump discharge lines are filled with (continued) water. The LPCI and CS System discharge lines are kept full of water using a "keep full" system (jockey pump system).

The HPCI System is normally aligned to the CSTs. The height of water in the CSTs is sufficient to maintain the piping full of water up to the first isolation valve. The relative height of the feedwater line connection for HPCI is such that the water in the feedwater lines keeps the remaining portion of the HPCI discharge line full of water.

Therefore, HPCI does not require a "keep full" system.

The ADS (Ref. 4) consists of 7 of the 11 S/RVs. It is designed to provide depressurization of the RCS during a small break LOCA if HPCI fails or is unable to maintain required water level in the RPV. ADS operation reduces the RPV pressure to within the operating pressure range of the low pressure ECCS subsystems (CS and LPCI), so that these subsystems can provide coolant inventory makeup. Each of the S/RVs used for automatic depressurization is equipped with one air accumulator and associated inlet check valves.

The accumulator provides the pneumatic power to actuate the valves. One of the ADS valves shares an accumulator with a non-ADS valve.

APPLICABLE The ECCS performance is evaluated for the entire spectrum of SAFETY ANALYSES break sizes for a postulated LOCA. The accidents for which ECCS operation is required are presented in References 5, 6, and 7. The required analyses and assumptions are defined in Reference 8. The results of these analyses are also described in Reference 9.

This LCO helps to ensure that the following acceptance criteria for the ECCS, established by 10 CFR 50.46 (Ref. 10), will be met following a LOCA, assuming the worst case single active component failure in the ECCS:

a. Maximum fuel element cladding temperature is , 2200'F;

b. Maximum cladding oxidation is

0.17 times the total cladding thickness before oxidation;

c. Maximum hydrogen generation from a zirconium water reaction is

0.01 times the hypothetical amount that would be generated if all of the metal in the cladding surrounding the fuel, excluding the cladding surrounding the plenum volume, were to react; (continued)

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ECCS - Operating B 3.5.L BASES APPLICABLE d. The core is maintained in a coolable geometry; and SAFETY ANALYSES (continued) e. Adequate long term cooling capability is maintained.

The limiting single failures are discussed in Reference 5.

For a LOCA due to a large recirculation pump suction line pipe break, failure of the Division 2 125 VDC battery is considered the most severe failure. For a small break LOCA, HPCI failure is the most severe failure. In the analysis of events requiring ADS operation, it is assumed that only five of the seven ADS valves operate. Since six ADS valves are required to be OPERABLE, the explicit assumption of the failure of an ADS valve is not considered in the analysis.

The remaining OPERABLE ECCS subsystems provide the capability to adequately cool the core and prevent excessive fuel damage.

The ECCS satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii)

(Ref. 11).

LCO Each ECCS injection/spray subsystem and six ADS valves are required to be OPERABLE. The ECCS injection/spray subsystems are defined as the two CS subsystems, the two LPCI subsystems (which includes both pumps per subsystem),

and one HPCI System. The low pressure ECCS injection/spray subsystems are defined as the two CS subsystems and the two LPCI subsystems.

With less than the required number of ECCS subsystems OPERABLE, the potential exists that during a limiting design basis LOCA concurrent with the worst case single active component failure, the limits specified in Reference 10 could be exceeded. All ECCS subsystems must therefore be OPERABLE to satisfy the single failure criterion required by Reference 10.

LPCI subsystems may be considered OPERABLE during alignment and operation for decay heat removal when below the actual RHR cut in permissive pressure in MODE 3, if capable of being manually realigned (remote or local) to the LPCI mode and not otherwise inoperable. Alignment and operation for decay heat removal includes when the system is being realigned from or to the RHR shutdown cooling mode. At these low pressures and decay heat levels, a reduced complement of ECCS subsystems should provide the required core cooling, thereby allowing operation of RHR shutdown cooling when necessary.

(continued)

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ECCS - Operating B 3.5.1 BASES (continued)

APPLICABILITY All ECCS subsystems are required to be OPERABLE during MODES 1, 2, and 3, when there is considerable energy in the reactor core and core cooling would be required to prevent fuel damage in the event of a break in the primary system piping. In MODES 2 and 3, when reactor steam dome pressure is

150 psig, ADS and HPCI are not required to be OPERABLE because the low pressure ECCS subsystems can provide sufficient flow below this pressure. ECCS requirements for MODES 4 and 5 are specified in LCO 3.5.2, "ECCS-Shutdown."

ACTIONS A.1 If any one low pressure ECCS injection/spray subsystem is inoperable or if one LPCI pump in both LPCI subsystems is inoperable, the inoperable subsystem(s) must be restored to OPERABLE status within 7 days. In this Condition, the remaining OPERABLE subsystems provide adequate core cooling during a LOCA. However, overall ECCS reliability is reduced, because a single active component failure in one of the remaining OPERABLE subsystems, concurrent with a LOCA, may result in the ECCS not being able to perform its intended safety function. The 7 day Completion Time is consistent with the recommendations provided in a reliability study (Ref. 12) that evaluated the impact on ECCS availability, assuming various components and subsystems were taken out of service. The results were used to calculate the average availability of ECCS equipment needed to mitigate the consequences of a LOCA as a function of allowed outage times (i.e., Completion Times).

B.1 and B.2 If the inoperable low pressure ECCS subsystem(s) cannot be restored to OPERABLE status within the associated Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours0.5 days 0.0714 weeks 0.0164 months and to MODE 4 within 36 hours1.5 days 0.214 weeks 0.0493 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

C.1 and C.2 If the HPCI System is inoperable and the RCIC System is verified to be OPERABLE, the HPCI System must be restored to OPERABLE status within 14 days. In this condition, adequate (continued)

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ECCS- Operating B 3.5.L BASES ACTIONS C.1 and C.2 (continued) core cooling is ensured by the OPERABILITY of the redundant and diverse low pressure ECCS injection/spray subsystems in conjunction with ADS. Also, the RCIC System will automatically provide makeup water at most reactor operating pressures. Verification of RCIC OPERABILITY immediately is therefore required when HPCI is inoperable. This may be performed as an administrative check by examining logs or other information to determine if RCIC is out of service for maintenance or other reasons. It does not mean to perform the Surveillances needed to demonstrate the OPERABILITY of the RCIC System. If the OPERABILITY of the RCIC System cannot be verified, however, Condition G must be immediately entered. If a single active component fails concurrent with a design basis LOCA, there is a potential, depending on the specific failure, that the minimum required ECCS equipment will not be available. A 14 day Completion Time is consistent with the recommendations provided in a reliability study cited in Reference 12 and has been found to be acceptable through operating experience.

D.1 and D.2 If any one low pressure ECCS injection/spray subsystem or one LPCI pump in both LPCI subsystems is inoperable in addition to an inoperable HPCI System, the inoperable low pressure ECCS injection/spray subsystem(s) or the HPCI System must be restored to OPERABLE status within 72 hours3 days 0.429 weeks 0.0986 months .

In this condition, adequate core cooling is ensured by the OPERABILITY of the ADS and the remaining low pressure ECCS subsystems. However, the overall ECCS reliability is significantly reduced because a single active component failure in one of the remaining OPERABLE subsystems concurrent with a design basis LOCA may result in the ECCS not being able to perform its intended safety function.

Since both a high pressure system (HPCI) and low pressure subsystem are inoperable, a more restrictive Completion Time of 72 hours3 days 0.429 weeks 0.0986 months is required to restore either the HPCI System or the low pressure ECCS injection/spray subsystem to OPERABLE status. This Completion Time is consistent with the recommendations provided in a reliability study cited in Reference 12 and has been found to be acceptable through operating experience.

(continued)

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ECCS - Operating B 3.5.L BASES ACTIONS E.1 (continued)

The LCO requires six ADS valves to be OPERABLE in order to provide the ADS function. Reference 5 contains the results of an analysis that evaluated the effect of two of the seven ADS valves being out of service. This analysis shows that, assuming a failure of the HPCI System, operation of only five ADS valves will provide the required depressurization.

However, overall reliability of the ADS is reduced, because a single active component failure in the OPERABLE ADS valves could result in a reduction in depressurization capability.

Therefore, operation with five ADS valves is only allowed for a limited time. The 14 day Completion Time is consistent with the recommendations provided in a reliability study cited in Reference 12 and has been found to be acceptable through operating experience.

F.1 and F.2 If any one low pressure ECCS injection/spray subsystem or one LPCI pump in both LPCI subsystems is inoperable in addition to one required ADS valve inoperable, adequate core cooling is ensured by the OPERABILITY of HPCI and the remaining low pressure ECCS injection/spray subsystem(s).

However, overall ECCS reliability is reduced because a single active component failure concurrent with a design basis LOCA could result in the minimum required ECCS equipment not being available. Since both a high pressure system (ADS) and low pressure subsystem(s) are inoperable, a more restrictive Completion Time of 72 hours3 days 0.429 weeks 0.0986 months is required to restore either the low pressure ECCS subsystem(s) or the ADS valve to OPERABLE status. This Completion Time is consistent with the recommendations provided in a reliability study cited in Reference 12 and has been found to be acceptable through operating experience.

G.1 and G.2 If any Required Action and associated Completion Time of Condition C, D, E, or F is not met, or if two or more required ADS valves are inoperable, the plant must be brought to a condition in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours0.5 days 0.0714 weeks 0.0164 months and reactor steam dome pressure reduced to : 150 psig within 36 hours1.5 days 0.214 weeks 0.0493 months . The allowed (continued)

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ECCS- Operating B 3.5.L BASES ACTIONS G.1 and G.2 (continued)

Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

H.1 When multiple ECCS subsystems are inoperable, as stated in Condition H, the plant is in a condition outside of the accident analyses. Therefore, LCO 3.0.3 must be entered immediately.

SURVEILLANCE SR 3.5.1.1 REQUIREMENTS The flow path piping has the potential to develop voids and pockets of entrained air. Maintaining the pump discharge lines of the HPCI System, CS System, and LPCI subsystems full of water ensures that the ECCS will perform properly, injecting its full capacity into the RCS upon demand. This will also prevent a water hammer following an ECCS initiation signal. One acceptable method of ensuring that the lines are full is to vent at the high points and observe water flow through the vent. The 31 day Frequency is based on the gradual nature of void buildup in the ECCS piping, the procedural controls governing system operation, and operating experience.

SR 3.5.1.2 Verifying the correct alignment for manual, power operated, and automatic valves in the ECCS flow paths provides assurance that the proper flow paths will exist for ECCS operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these were verified to be in the correct position prior to locking, sealing, or securing. A valve that receives an initiation signal is allowed to be in a nonaccident position provided the valve will automatically reposition in the proper stroke time. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of potentially being mispositioned are in the correct position. This SR does not apply to valves (continued)

JAFNPP B 3.5.1-9 Revision 0

ECCS - Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.2 (continued)

REQUIREMENTS that cannot be inadvertently misaligned, such as check valves. For the HPCI System, this SR also includes the steam flow path for the turbine and the flow controller position.

The 31 day Frequency of this SR was derived from the Inservice Testing Program requirements for performing valve testing at least once every 92 days. The Frequency of 31 days is further justified because the valves are operated under procedural control and because improper valve position would only affect a single subsystem. This Frequency has been shown to be acceptable through operating experience.

In MODE 3 with reactor dome pressure less than the actual RHR cut in permissive pressure, the RHR System may be required to operate in the shutdown cooling mode to remove decay heat and sensible heat from the reactor. Therefore, this SR is modified by a Note that allows LPCI subsystems to be considered OPERABLE during alignment and operation for decay heat removal, if capable of being manually realigned (remote or local) to the LPCI mode and not otherwise inoperable. Alignment and operation for decay heat removal includes when the system is being realigned from or to the RHR shutdown cooling mode. At the low pressures and decay heat loads associated with operation in MODE 3 with reactor steam dome pressure less than the shutdown cooling permissive pressure, a reduced complement of low pressure ECCS subsystems should provide the required cooling, thereby allowing operation of RHR shutdown cooling, when necessary.

SR 3.5.1.3 Verification every 31 days that ADS pneumatic supply header pressure is Ž 95 psig ensures adequate pneumatic pressure for reliable ADS operation. The accumulator on each ADS valve provides pneumatic pressure for valve actuation. The design pneumatic supply pressure requirements for the accumulator are such that, following a failure of the pneumatic supply to the accumulator, at least one valve actuation can occur with the drywell at 70% of design pressure (Ref. 13). The ECCS safety analysis assumes only one actuation to achieve the depressurization required for operation of the low pressure ECCS. This minimum required pressure of , 95 psig is provided by the ADS nitrogen (continued)

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ECCS- Operating B 3.5.1L BASES SURVEILLANCE SR 3.5.1.3 (continued)

REQUIREMENTS supply. The 31 day Frequency takes into consideration administrative controls over operation of the pneumatic system and alarms for low pneumatic pressure.

SR 3.5.1.4 Verification every 31 days that the RHR System cross tie valves are closed and power to the motor operated valve is disconnected ensures that each LPCI subsystem remains independent and a failure of the flow path in one subsystem will not affect the flow path of the other LPCI subsystem.

Acceptable methods of removing power to the operator include de-energizing breaker control power or racking out or removing the breaker. If one or more of the RHR System cross tie valves are open or power has not been removed from the motor operated valve, both LPCI subsystems must be considered inoperable. In addition, plant procedures require the motor operated cross tie valve to be chain locked closed and the manual cross tie valve to be locked closed. The 31 day Frequency has been found acceptable, considering that these valves are under strict administrative controls that will ensure the valves continue to remain closed with either control or motive power removed.

SR 3.5.1.5 Cycling open and closed each LPCI motor operated valve independent power supply battery charger AC input breaker and verification that each LPCI inverter output has a voltage of ; 576 V and . 624 V while supplying its respective bus demonstrates the capability of the supply to become independent from emergency AC power and that the AC electrical power is available to ensure proper operation of the associated LPCI injection and heat exchanger bypass valves and the recirculation pump discharge valve. Each inverter and battery charger AC input breaker must be OPERABLE for the associated LPCI subsystem to be OPERABLE.

The 31 day Frequency has been found acceptable based on operating experience.

(continued)

JAFNPP B 3.5.1-11 Revision 0

ECCS - Operating B 3.5.L BASES SURVEILLANCE SR 3.5.1.6 REQUIREMENTS (continued) Cycling the recirculation pump discharge valves through one complete cycle of full travel demonstrates that the valves are mechanically OPERABLE and will close when required.

Upon initiation of an automatic LPCI subsystem injection signal, these valves are required to close to ensure full LPCI subsystem flow injection in the reactor via the recirculation jet pumps. De-energizing the valve in the closed position will also ensure the proper flow path for the LPCI subsystem. Acceptable methods of de-energizing the valve include de-energizing breaker control power, racking out the breaker or removing the breaker.

The specified Frequency is once during reactor startup before THERMAL POWER is > 25% RTP. However, this SR is modified by a Note that states the Surveillance is only required to be performed if the last performance was more than 31 days ago. Verification during reactor startup prior to reaching > 25% RTP is an exception to the normal Inservice Testing Program generic valve cycling Frequency of 92 days, but is considered acceptable due to the demonstrated reliability of these valves. If the valve is inoperable and in the open position, the associated LPCI subsystem must be declared inoperable.

SR 3.5.1.7, SR 3.5.1.8, and SR 3.5.1.9 The performance requirements of the low pressure ECCS pumps are determined through application of the 10 CFR 50, Appendix K criteria (Ref. 8). This periodic Surveillance is performed (in accordance with the ASME Code,Section XI, requirements for the ECCS pumps) to verify that the ECCS pumps will develop at least the flow rates required by the respective analyses. The low pressure ECCS pump flow rates ensure that adequate core cooling is provided to satisfy the acceptance criteria of Reference 10. The pump flow rates are verified against a system head equivalent to the RPV pressure expected during a LOCA. The total system pump outlet pressure is adequate to overcome the elevation head pressure between the pump suction and the vessel discharge, the piping friction losses, and RPV pressure present during a LOCA. These values may be established during preoperational testing.

The flow tests for the HPCI System are performed at two different pressure ranges such that system capability to provide rated flow against a system head corresponding to (continued)

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ECCS - Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.7, SR 3.5.1.8, and SR 3.5.1.9 (continued)

REQUIREMENTS reactor pressure is tested at both the higher and lower operating ranges of the system. The required system head should overcome the RPV pressure and associated discharge line losses. Adequate reactor steam pressure must be available to perform these tests. Additionally, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure when the HPCI System diverts steam flow.

Therefore, sufficient time is allowed after adequate pressure and flow are achieved to perform these tests.

Adequate reactor steam pressure must be 2 970 psig to perform SR 3.5.1.8 and > 150 psig to perform SR 3.5.1.9.

Adequate steam flow is represented by at least one turbine bypass valve open or main turbine generator load is greater than 100 MWe. Reactor startup is allowed prior to performing the low pressure Surveillance test because the reactor pressure is low and the time allowed to satisfactorily perform the Surveillance test is short. The reactor pressure is allowed to be increased to normal operating pressure since it is assumed that the low pressure test has been satisfactorily completed and there is no indication or reason to believe that HPCI is inoperable.

Therefore, SR 3.5.1.8 and SR 3.5.1.9 are modified by Notes that state the Surveillances are not required to be performed until 12 hours0.5 days 0.0714 weeks 0.0164 months after the reactor steam pressure and flow are adequate to perform the test. The 12 hours0.5 days 0.0714 weeks 0.0164 months allowed for performing the flow test after the required pressure and flow are reached is sufficient to achieve stable conditions for testing and provides reasonable time to complete the SRs.

The Frequency for SR 3.5.1.7 and SR 3.5.1.8 is in accordance with the Inservice Testing Program requirements. The 24 month Frequency for SR 3.5.1.9 is based on the need to perform the Surveillance under the conditions that apply during a startup from a plant outage. Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

(continued)

JAFNPP B 3.5.1-13 Revision 0

ECCS - Operating B 3.5.1-BASES SURVEILLANCE SR 3.5.1.10 REQUIREMENTS (continued) The ECCS subsystems are required to actuate automatically to perform their design functions. This Surveillance verifies that, with a required system initiation signal (actual or simulated), the automatic initiation logic of HPCI, CS, and LPCI will cause the systems or subsystems to operate as designed, including actuation of the system throughout its emergency operating sequence, automatic pump startup and actuation of all automatic valves to their required positions. The HPCI System actual or simulated automatic actuation test must be performed with adequate steam pressure for verification of automatic pump startup.

Additionally, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure when the HPCI System diverts steam flow. Thus, sufficient time is allowed after adequate pressure and flow are achieved to perform this test associated with the HPCI System. Adequate reactor steam dome pressure is > 150 psig. Adequate steam flow is represented by at least one turbine bypass valve open. This SR also ensures that the HPCI System will automatically restart on an RPV low water level (Level 2) signal received subsequent to an RPV high water level (Level 8) trip. In addition, this SR also ensures that the HPCI suction is automatically transferred from the CSTs to the suppression pool on high suppression pool water level or low CST water level. The LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.1 overlaps this Surveillance to provide complete testing of the assumed safety function.

For CS and LPCI, the 24 month Frequency is based on the need to perform the Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. For HPCI, the 24 month Frequency is based on the need to perform the surveillance under conditions that apply during a startup from a plant outage. Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

This SR is modified by two Notes. Note 1 states that for the HPCI System, the Surveillance is not required to be performed until 12 hours0.5 days 0.0714 weeks 0.0164 months after the reactor steam pressure and flow are adequate to perform the test. The 12 hours0.5 days 0.0714 weeks 0.0164 months allowed for performing the actual or simulated automatic actuation for the HPCI System after the required pressure (continued)

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ECCS - Operating B 3.5.L BASES SURVEILLANCE SR 3.5.1.10 (continued)

REQUIREMENTS and flow are reached is sufficient to achieve stable conditions for testing and provides reasonable time to complete the SR. Note 2 excludes vessel injection/spray during the Surveillance. Since all active components are testable and full flow can be demonstrated by recirculation through the test line, coolant injection into the RPV is not required during the Surveillance.

SR 3.5.1.11 The ADS designated S/RVs are required to actuate automatically upon receipt of specific initiation signals.

A system functional test is performed to demonstrate that the mechanical portions of the ADS function (i.e.,

solenoids) operate as designed when initiated either by an actual or simulated initiation signal, causing proper actuation of all the required components. SR 3.5.1.13 and the LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.1 overlap this Surveillance to provide complete testing of the assumed safety function. The 24 month Frequency is based on the need to perform the Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle.

Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

This SR is modified by a Note that excludes valve actuation since the valves are individually tested in accordance with SR 3.5.1.13. This prevents the possibility of an RPV pressure blowdown.

SR 3.5.1.12 A LPCI motor operated valve independent power supply subsystem inverter test is a test of the inverter's capability, as found, to satisfy the design requirements (inverter duty cycle). The discharge rate and test length correspond to the design duty cycle requirements.

(continued)

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ECCS- Operating B 3.5.1L BASES SURVEILLANCE SR 3.5.1.12 (continued)

REQUIREMENTS The Frequency of 24 months is acceptable, given plant conditions required to perform the test and the other requirements existing to ensure adequate LPCI inverter performance during the 24 month interval. In addition, the Frequency is intended to be consistent with expected fuel cycle lengths.

SR 3.5.1.13 A manual actuation of each required ADS valve is performed while bypassing main steam flow to the condenser and observing 2 10% closure of the turbine bypass valves to verify that the valve and solenoid are functioning properly and that no blockage exists in the S/RV discharge lines.

This can also be demonstrated by the response of the turbine control or bypass valve or by a change in the measured flow or by any other method suitable to verify steam flow.

Adequate reactor steam dome pressure must be available to perform this test to avoid damaging the valve. Also, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure when the ADS valves divert steam flow upon opening.

Sufficient time is therefore allowed after the required pressure and flow are achieved to perform this SR. Adequate pressure at which this SR is to be performed is 2 970 psig (the pressure consistent with vendor recommendations).

Adequate steam flow is represented by at least two ?r more turbine bypass valves open or total steam flow Ž 10 lb/hr.

These conditions will require the plant to be in MODE 1, which has been shown to be an acceptable condition to perform this test. This test causes a small neutron flux transient which may cause a scram in MODE 2 while operating close to the Average Power Range Monitors Neutron Flux-High (Startup) Allowable Value. Reactor startup is allowed prior to performing this SR because valve OPERABILITY and the setpoints for overpressure protection are verified, per ASME requirements, prior to valve installation. Therefore, this SR is modified by a Note that states the Surveillance is not required to be performed until 12 hours0.5 days 0.0714 weeks 0.0164 months after reactor steam pressure and flow are adequate to perform the test. The 12 hours0.5 days 0.0714 weeks 0.0164 months allowed for manual actuation after the required pressure and flow are reached is sufficient to achieve stable conditions and provides adequate time to complete the Surveillance. SR 3.5.1.11 and the LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.1 overlap this Surveillance to provide complete testing of the assumed safety function.

(continued)

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ECCS- Operating B 3.5.1L BASES SURVEILLANCE SR 3.5.1.13 (continued)

REQUIREMENTS The Frequency of 24 months on a STAGGERED TEST BASIS ensures that both solenoids for each ADS valve are alternately tested. The Frequency is based on the need to perform the Surveillance under the conditions that apply during a startup from a plant outage. Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

REFERENCES 1. UFSAR, Section 6.4.3.

2. UFSAR, Section 6.4.4.

3. UFSAR, Section 6.4.1.

4. UFSAR, Section 6.4.2.

5. NEDC-31317P, Revision 2, James A. FitzPatrick Nuclear Power Plant SAFER/GESTR-LOCA, Loss-of-Coolant Accident Analysis, April 1993.

6. UFSAR, Section 14.6.1.5.

7. UFSAR, Section 14.6.1.3.

8. 10 CFR 50, Appendix K.

9. UFSAR, Section 6.5.

10. 10 CFR 50.46.

11. 10 CFR 50.36(c)(2)(ii).

12. Memorandum from R.L. Baer (NRC) to V. Stello, Jr.

(NRC), Recommended Interim Revisions to LCOs for ECCS Components, December 1, 1975.

13. UFSAR, Section 4.4.5.

JAFNPP B 3.5.1-17 Revision 0

ECCS- Shutdown B 3.5.2 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM B 3.5.2 ECCS-Shutdown BASES BACKGROUND A description of the Core Spray (CS) System and the low pressure coolant injection (LPCI) mode of the Residual Heat Removal (RHR) System is provided in the Bases for LCO 3.5.1.

"ECCS - Operating."

APPLICABLE The ECCS performance is evaluated for the entire spectrum of SAFETY ANALYSES break sizes for a postulated loss of coolant accident (LOCA). The long term cooling analysis following a design basis LOCA (Ref. 1) demonstrates that only one low pressure ECCS injection/spray subsystem is required, post LOCA, to maintain adequate reactor vessel water level in the event of an inadvertent vessel draindown. It is reasonable to assume, based on engineering judgement, that while in MODES 4 and 5, one low pressure ECCS injection/spray subsystem can maintain adequate reactor vessel water level. To provide redundancy, a minimum of two low pressure ECCS injection/spray subsystems are required to be OPERABLE in MODES 4 and 5.

The low pressure ECCS subsystems satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii) (Ref. 2).

LCO Two low pressure ECCS injection/spray subsystems are required to be OPERABLE. The low pressure ECCS injection/

spray subsystems consist of two CS subsystems and two LPCI subsystems. Each CS subsystem consists of one motor driven pump, piping, and valves to transfer water from the suppression pool or from both condensate storage tanks (CSTs) to the reactor pressure vessel (RPV). The CST suction source consists of two CSTs connected in parallel.

Each OPERABLE LPCI subsystem consists of one motor driven pump, piping, and valves to transfer water from the suppression pool to the RPV. Only a single LPCI pump is required per subsystem because of the larger injection capacity in relation to a CS subsystem. In MODES 4 and 5, the RHR System cross tie valves are not required to be closed.

One LPCI subsystem may be considered OPERABLE during alignment and operation for decay heat removal, if capable of being manually realigned (remote or local) to the LPCI mode and is not otherwise inoperable. Alignment and (continued)

JAFNPP B 3.5.2-1 Revision 0

ECCS - Shutdown B 3.5.2_

BASES LCO operation for decay heat removal includes when the system is (continued) realigned from or to the RHR shutdown cooling mode. Because of low pressure and low temperature conditions in MODES 4 and 5, sufficient time will be available to manually align and initiate LPCI subsystem operation to provide core cooling prior to postulated fuel uncovery.

APPLICABILITY OPERABILITY of the low pressure ECCS injection/spray subsystems is required in MODES 4 and 5 to ensure adequate coolant inventory and sufficient heat removal capability for the irradiated fuel in the core in case of an inadvertent draindown of the vessel. Requirements for ECCS OPERABILITY during MODES 1, 2, and 3 are discussed in the Applicability section of the Bases for LCO 3.5.1. ECCS subsystems are not required to be OPERABLE during MODE 5 with the spent fuel storage pool gates removed and the water level maintained at 2 22 feet 2 inches above the RPV flange. This provides sufficient coolant inventory to allow operator action to terminate the inventory loss prior to fuel uncovery in case of an inadvertent draindown.

The Automatic Depressurization System is not required to be OPERABLE during MODES 4 and 5 because the RPV pressure is

150 psig, and the CS System and the LPCI subsystems can provide core cooling without any depressurization of the primary system.

The High Pressure Coolant Injection System is not required to be OPERABLE during MODES 4 and 5 since the low pressure ECCS injection/spray subsystems can provide sufficient flow to the vessel.

ACTIONS A.1 and B.1 If any one required low pressure ECCS injection/spray subsystem is inoperable, the inoperable subsystem must be restored to OPERABLE status in 4 hours0.167 days 0.0238 weeks 0.00548 months . In this condition, the remaining OPERABLE subsystem can provide sufficient vessel flooding capability to recover from an inadvertent vessel draindown. However, overall system reliability is reduced because a single active component failure in the remaining OPERABLE subsystem concurrent with a vessel draindown could result in the ECCS not being able to perform its intended function. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time for restoring the required low pressure ECCS injection/spray (continued)

JAFNPP B 3.5.2-2 Revision 0

ECCS - Shutdown B 3.5.2 BASES ACTIONS A.1 and B.1 (continued) subsystem to OPERABLE status is based on engineering judgment that considered the remaining available subsystem and the low probability of a vessel draindown event.

With the inoperable subsystem not restored to OPERABLE status in the required Completion Time, action must be immediately initiated to suspend operations with a potential for draining the reactor vessel (OPDRVs) to minimize the probability of a vessel draindown and the subsequent potential for fission product release. Actions must continue until OPDRVs are suspended.

C.1, C.2, D.1, D.2, and D.3 With both of the required ECCS injection/spray subsystems inoperable, all coolant inventory makeup capability may be unavailable. Therefore, actions must immediately be initiated to suspend OPDRVs to minimize the probability of a vessel draindown and the subsequent potential for fission product release. Actions must continue until OPDRVs are suspended. One ECCS injection/spray subsystem must also be restored to OPERABLE status within 4 hours0.167 days 0.0238 weeks 0.00548 months . The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time to restore at least one low pressure ECCS injection/spray subsystem to OPERABLE status ensures that prompt action will be taken to provide the required cooling capacity or to initiate actions to place the plant in a condition that minimizes any potential fission product release to the environment.

If at least one low pressure ECCS injection/spray subsystem is not restored to OPERABLE status within the 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time, additional actions are required to minimize any potential fission product release to the environment.

This includes ensuring secondary containment is OPERABLE; one standby gas treatment subsystem is OPERABLE; and secondary containment isolation capability is available in each associated penetration flow path not isolated that is assumed to be isolated to mitigate radioactivity releases (i.e., at least one secondary containment isolation valve and associated instrumentation are OPERABLE or acceptable administrative controls assure isolation capability. These administrative controls consist of stationing a dedicated operator who is in continuous communication with the control room, at the controls of the isolation device. In this way, the penetration can be rapidly isolated when a need for (continued)

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ECCS - Shutdown B 3.5.2_

BASES ACTIONS C.1, C.2, D.1, D.2, and D.3 (continued) secondary containment isolation is indicated). OPERABILITY may be verified by an administrative check, or by examining logs or other information, to determine whether the components are out of service for maintenance or other reasons. It is not necessary to perform the Surveillances needed to demonstrate the OPERABILITY of the components.

If, however, any required component is inoperable, then it must be restored to OPERABLE status. In this case, the Surveillance may need to be performed to restore the component to OPERABLE status. Actions must continue until all required components are OPERABLE.

SURVEILLANCE SR 3.5.2.1 and SR 3.5.2.2 REQUIREMENTS The minimum water level of 10.33 ft required for the suppression pool is periodically verified to ensure that the suppression pool will provide adequate net positive suction head (NPSH) for the CS System and LPCI subsystem pumps, recirculation volume, and vortex prevention. With the suppression pool water level less than the required limit, all ECCS injection/spray subsystems are inoperable unless they are aligned to an OPERABLE CST.

When suppression pool level is < 10.33 ft, the CS System is considered OPERABLE only if it can take suction from both CSTs, and the CST water level is sufficient to provide the required NPSH for the CS pump. Therefore, a verification that either the suppression pool water level is 2 10.33 ft or that CS is aligned to take suction from both CSTs and the CSTs contain 2 354,000 gallons (two tanks) of water, equivalent to 324 inches (27 ft), ensures that the CS System can supply at least 50,000 gallons of makeup water to the RPV. An excess amount of water remains as a supplementary volume and to ensure adequate CS pump NPSH. The CS suction is uncovered at approximately 258,000 gallons (two tanks).

However, as noted, only one required CS subsystem may take credit for the CST option during OPDRVs. During OPDRVs, the volume in the CSTs may not provide adequate makeup if the RPV were completely drained. Therefore, only one CS subsystem is allowed to use the CSTs. This ensures the other required ECCS subsystem has adequate makeup volume.

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency of these SRs was developed considering operating experience related to suppression pool water level and CST water level variations and instrument drift during (continued)

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ECCS - Shutdown B 3.5.2 BASES SURVEILLANCE SR 3.5.2.1 and SR 3.5.2.2 (continued)

REQUIREMENTS the applicable MODES. Furthermore, the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal suppression pool or CST water level condition.

SR 3.5.2.3, SR 3.5.2.5, and SR 3.5.2.6 The Bases provided for SR 3.5.1.1, SR 3.5.1.7, and SR 3.5.1.10 are applicable to SR 3.5.2.3, SR 3.5.2.5, and SR 3.5.2.6, respectively.

SR 3.5.2.4 Verifying the correct alignment for manual, power operated, and automatic valves in the ECCS flow paths provides assurance that the proper flow paths will exist for ECCS operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve that receives an initiation signal is allowed to be in a nonaccident position provided the valve will automatically reposition in the proper stroke time. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of potentially being mispositioned are in the correct position.

This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. The 31 day Frequency is appropriate because the valves are operated under procedural control and the probability of their being mispositioned during this time period is low.

In MODES 4 and 5, the RHR System may be required to operate in the shutdown cooling mode to remove decay heat and sensible heat from the reactor. Therefore, this SR is modified by a Note that allows one LPCI subsystem to be considered OPERABLE during alignment and operation for shutdown cooling if capable of being manually realigned (remote or local) to the LPCI mode and not otherwise inoperable. Alignment and operation for decay heat removal includes when the system is being realigned from or to the RHR shutdown cooling mode. Because of the low pressure and low temperature conditions in MODE 4 and 5 sufficient time (continued)

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ECCS - Shutdown B 3.5.2_

BASES SURVEILLANCE SR 3.5.2.4 (continued)

REQUIREMENTS will be available to manually align and initiate LPCI subsystem operation to provide core cooling prior to postulated fuel uncovery. This will ensure adequate core cooling if an inadvertent RPV draindown should occur.

REFERENCES 1. UFSAR, Section 6.5.3.

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RCIC System B 3.5.3 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM B 3.5.3 RCIC System BASES BACKGROUND The RCIC System is not part of the ECCS: however, the RCIC System is included with the ECCS section because of their similar functions.

The RCIC System is designed to operate either automatically or manually following reactor pressure vessel (RPV) isolation accompanied by a loss of coolant flow from the feedwater system to provide adequate core cooling and control of the RPV water level. Under these conditions, the High Pressure Coolant Injection (HPCI) and RCIC systems perform similar functions. The RCIC System design requirements ensure that the criteria of Reference 1 are satisfied.

The RCIC System (Ref. 2) consists of a steam driven turbine pump unit, piping and valves to provide steam to the turbine, as well as piping and valves to transfer water from the suction source to the core via the feedwater system line, where the coolant is distributed within the RPV through the feedwater sparger. Suction piping is provided from the condensate storage tanks (CSTs) and the suppression pool. Pump suction is normally aligned to the CSTs to minimize injection of suppression pool water into the RPV.

However, if the CST water supply is low, an automatic transfer to the suppression pool water source ensures a water supply for continuous operation of the RCIC System.

The steam supply to the turbine is piped from the "B" main steam line upstream of the associated inboard main steam line isolation valve.

The RCIC System is designed to provide core cooling for a wide range of reactor pressures (150 psig to 1195 psig).

Upon receipt of an initiation signal, the RCIC turbine accelerates to a specified speed. As the RCIC flow increases, the turbine control valve is automatically adjusted to maintain design flow. Exhaust steam from the RCIC turbine is discharged to the suppression pool. A full flow test line is provided to route water to the CSTs to allow testing of the RCIC System during normal operation without injecting water into the RPV.

The RCIC pump is provided with a minimum flow bypass line, which discharges to the suppression pool. The valve in this line automatically opens to prevent pump damage due to (continued)

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RCIC System B 3.5.3-BASES BACKGROUND overheating when other discharge line valves are closed. To (continued) ensure rapid delivery of water to the RPV and to minimize water hammer effects, the RCIC System discharge piping is kept full of water. The RCIC System is normally aligned to the CSTs. The height of water in the CSTs is sufficient to maintain the piping full of water up to the first isolation valve. The relative height of the feedwater line connection for RCIC is such that the water in the feedwater lines keeps the remaining portion of the RCIC discharge line full of water. Therefore, RCIC does not require a "keep full" system.

APPLICABLE The function of the RCIC System is to respond to transient SAFETY ANALYSES events by providing makeup coolant to the reactor. The RCIC System is not an Engineered Safeguard System and no credit is taken in the safety analyses for RCIC System operation.

The RCIC System satisfies Criterion 4 of 10 CFR 50.36(c)(2)(ii) (Ref. 3).

LCO The OPERABILITY of the RCIC System provides adequate core cooling such that actuation of any of the low pressure ECCS subsystems is not required in the event of RPV isolation accompanied by a loss of feedwater flow. The RCIC System has sufficient capacity for maintaining RPV inventory during an isolation event.

APPLICABILITY The RCIC System is required to be OPERABLE during MODE 1, and MODES 2 and 3 with reactor steam dome pressure

> 150 psig, since RCIC is the primary non-ECCS water source for core cooling when the reactor is isolated and pressurized. In MODES 2 and 3 with reactor steam dome pressure

150 psig, and in MODES 4 and 5, RCIC is not required to be OPERABLE since the low pressure ECCS injection/spray subsystems can provide sufficient flow to the RPV.

ACTIONS A.1 and A.2 If the RCIC System is inoperable during MODE 1, or MODE 2 or 3 with reactor steam dome pressure > 150 psig, and the HPCI System is verified to be OPERABLE, the RCIC System must be restored to OPERABLE status within 14 days. In this Condition, loss of the RCIC System will not affect the overall plant capability to provide makeup inventory at high reactor pressure since the HPCI System is the only high (continued)

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RCIC System B 3.5.3_

BASES ACTIONS A.1 and A.2 (continued) pressure system assumed to function during a loss of coolant accident (LOCA). OPERABILITY of HPCI is therefore verified immediately when the RCIC System is inoperable. This may be performed as an administrative check, by examining logs or other information, to determine if HPCI is out of service for maintenance or other reasons. It does not mean it is necessary to perform the Surveillances needed to demonstrate the OPERABILITY of the HPCI System. If the OPERABILITY of the HPCI System cannot be verified, however, Condition B must be immediately entered. For transients and certain abnormal events with no LOCA, RCIC (as opposed to HPCI) is the preferred source of makeup coolant because of its relatively small capacity, which allows easier control of the RPV water level. Therefore, a limited time is allowed to restore the inoperable RCIC to OPERABLE status.

The 14 day Completion Time is consistent with the recommendations in a reliability study (Ref. 4) that evaluated the impact on ECCS availability, assuming various components and subsystems were taken out of service. The results were used to calculate the average availability of ECCS equipment needed to mitigate the consequences of a LOCA as a function of allowed outage times (AOTs). Because of similar functions of HPCI and RCIC, the AOTs (i.e.,

Completion Times) determined for HPCI are also applied to RCIC.

B.1 and B.2 If the RCIC System cannot be restored to OPERABLE status within the associated Completion Time, or if the HPCI System is simultaneously inoperable, the plant must be brought to a condition in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours0.5 days 0.0714 weeks 0.0164 months and reactor steam dome pressure reduced to

150 psig within 36 hours1.5 days 0.214 weeks 0.0493 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

(continued)

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RCIC BSystem 3.5.&

BASES (continued)

SURVEILLANCE SR 3.5.3.1 REQUIREMENTS The flow path piping has the potential to develop voids and pockets of entrained air. Maintaining the pump discharge line of the RCIC System full of water ensures that the system will perform properly, injecting its full capacity into the Reactor Coolant System upon demand. This will also prevent a water hammer following an initiation signal. One acceptable method of ensuring the line is full is to vent at the high points and observe water flow through the vent.

The 31 day Frequency is based on the gradual nature of void buildup in the RCIC piping, the procedural controls governing system operation, and operating experience.

SR 3.5.3.2 Verifying the correct alignment for manual, power operated, and automatic valves in the RCIC flow path provides assurance that the proper flow path will exist for RCIC operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve that receives an initiation signal is allowed to be in a nonaccident position provided the valve will automatically reposition in the proper stroke time. This SR does not require any testing or valve manipulation: rather, it involves verification that those valves capable of potentially being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. For the RCIC System, this SR also includes the steam flow path for the turbine and the flow controller position.

The 31 day Frequency of this SR was derived from the Inservice Testing Program requirements for performing valve testing at least once every 92 days. The Frequency of 31 days is further justified because the valves are operated under procedural control and because improper valve position would affect only the RCIC System. This Frequency has been shown to be acceptable through operating experience.

SR 3.5.3.3 and SR 3.5.3.4 The RCIC pump flow rates ensure that the system can maintain reactor coolant inventory during pressurized conditions with the RPV isolated. The flow tests for the RCIC System are performed at two different pressure ranges such that system (continued)

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RCIC BSystem 3.5.a.

BASES SURVEILLANCE SR 3.5.3.3 and SR 3.5.3.4 (continued)

REQUIREMENTS capability to provide rated flow against a system head corresponding to reactor pressure is tested both at the higher and lower operating ranges of the system. The required system head should overcome the RPV pressure and associated discharge line losses. Adequate reactor steam pressure must be available to perform these tests.

Additionally, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure when the RCIC System diverts steam flow. Therefore, sufficient time is allowed after adequate pressure and flow are achieved to perform these SRs.

Adequate reactor steam pressure must be Ž 970 psig to perform SR 3.5.3.3 and > 150 psig to perform SR 3.5.3.4.

Adequate steam flow is represented by at least one turbine bypass valve open, or main turbine generator load is greater than 100 MWe. Reactor startup is allowed prior to performing the low pressure Surveillance because the reactor pressure is low and the time allowed to satisfactorily perform the Surveillance is short. The reactor pressure is allowed to be increased to normal operating pressure since it is assumed that the low pressure Surveillance has been satisfactorily completed and there is no indication or reason to believe that RCIC is inoperable.

These SRs are modified by Notes that state the Surveillances are not required to be performed until 12 hours0.5 days 0.0714 weeks 0.0164 months after the reactor steam pressure and flow are adequate to perform the test. The 12 hours0.5 days 0.0714 weeks 0.0164 months allowed for performing the flow test after the required pressure and flow are reached is sufficient to achieve stable conditions for testing and provides reasonable time to complete the SR.

A 92 day Frequency for SR 3.5.3.3 is consistent with the Inservice Testing Program requirements. The 24 month Frequency for SR 3.5.3.4 is based on the need to perform the Surveillance under conditions that apply during a startup from a plant outage. Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle.

Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

SR 3.5.3.5 The RCIC System is required to actuate automatically in order to verify its design function satisfactorily. This Surveillance verifies that, with a required system (continued)

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RCIC System B 3.5.3_

BASES SURVEILLANCE SR 3.5.3.5 (continued)

REQUIREMENTS initiation signal (actual or simulated), the automatic initiation logic of the RCIC System will cause the system to operate as designed, including actuation of the system throughout its emergency operating sequence: that is, automatic pump startup and actuation of all automatic valves to their required positions. This test also ensures the RCIC System will automatically restart on an RPV low water level (Level 2) signal received subsequent to an RPV high water level (Level 8) signal (Level 8 signal closes RCIC steam inlet valve, and subsequent Level 2 signal will re open valve) and that the suction is automatically transferred from the CST to the suppression pool. The LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.2 overlaps this Surveillance to provide complete testing of the assumed design function.

The 24 month Frequency is based on the need to perform the Surveillance under the conditions that apply during a startup from a plant outage. Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

This SR is modified by Note 1 that says the Surveillance is not required to be performed until 12 hours0.5 days 0.0714 weeks 0.0164 months after the reactor steam pressure and flow are adequate to perform the test. The time allowed for this test after required pressure and flow are reached is sufficient to achieve stable conditions for testing and provides a reasonable time to complete the SR. Adequate reactor pressure must be available to perform this test. Additionally, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure when the RCIC System diverts steam flow. Thus, sufficient time is allowed after adequate pressure and flow are achieved to perform this test. Adequate reactor steam pressure is > 150 psig. Adequate steam flow is represented by at least one turbine bypass valve open. Reactor startup is allowed prior to performing this test because the reactor pressure is low and the time allowed to satisfactorily perform the test is short.

This SR is modified by Note 2 that excludes vessel injection during the Surveillance. Since all active components are testable and full flow can be demonstrated by recirculation through the test line, coolant injection into the RPV is not required during the Surveillance.

(continued)

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RCIC System B 3.5.3-BASES (continued)

REFERENCES 1. UFSAR, Section 16.6.

2. UFSAR, Section 4.7.

4. Memorandum from R.L. Baer (NRC) to V. Stello, Jr.

(NRC), Recommended Interim Revisions to LCOs for ECCS Components, December 1, 1975.

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Primary Containment B 3.6.1.L B 3.6 CONTAINMENT SYSTEMS B 3.6.1.1 Primary Containment BASES BACKGROUND The function of the primary containment is to isolate and contain fission products released from the Reactor Primary System following a Design Basis Loss of Coolant Accident (LOCA) and to confine the postulated release of radioactive material. The primary containment consists of the drywell (a steel pressure vessel in the shape of an inverted light bulb) and the suppression chamber (a steel pressure vessel in the shape of a torus) located below and encircling the drywell. The primary containment surrounds the Reactor Coolant System and provides an essentially leak tight barrier against an uncontrolled release of radioactive material to the environment.

The isolation devices for the penetrations in the primary containment boundary are a part of the containment leak tight barrier. To maintain this leak tight barrier:

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

1. capable of being closed by an OPERABLE automatic containment isolation system, or

2. closed by manual valves, blind flanges, or de-activated automatic valves secured in their closed positions, except as provided in LCO 3.6.1.3, "Primary Containment Isolation Valves (PCIVs)";

b. The primary containment air lock is OPERABLE, except as provided in LCO 3.6.1.2, "Primary Containment Air Locks"; and

c. All equipment hatches are closed.

This Specification ensures that the performance of the primary containment, in the event of a Design Basis Accident (DBA), meets the assumptions used in the safety analyses of References 1 and 2. SR 3.6.1.1.1 leakage rate requirements are specified in the Primary Containment Leakage Rate Testing Program which is in conformance with 10 CFR 50, Appendix J, Option B (Ref. 3), as modified by approved exemptions.

(continued)

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Primary Containment B 3.6.1.1_

BASES (continued)

APPLICABLE The safety design basis for the primary containment is that SAFETY ANALYSES it must withstand the pressures and temperatures of the limiting DBA without exceeding the design leakage rate.

The DBA that postulates the maximum release of radioactive material within primary containment is a Loss of Coolant Accident (LOCA). In the analysis of this accident, it is assumed that primary containment is OPERABLE such that release of fission products to the environment is controlled by the rate of primary containment leakage.

Analytical methods and assumptions involving the primary containment are presented in References 1 and 2. The safety analyses assume a nonmechanistic fission product release following a DBA, which forms the basis for determination of offsite doses. The fission product release is, in turn, based on an assumed leakage rate from the primary containment. OPERABILITY of the primary containment ensures that the leakage rate assumed in the safety analyses is not exceeded.

The maximum allowable leakage rate for the primary containment (L,) is 1.5% by weight of the containment air per 24 hours1 days 0.143 weeks 0.0329 months at the design basis LOCA maximum peak containment pressure (Pa) of 45 psig (Primary Containment Leakage Rate Testing Program).

Primary containment satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii) (Ref. 4).

LCO Primary containment OPERABILITY is maintained by limiting leakage to

1.0 La, except prior to the first startup after performing a required Primary Containment Leakage Rate Testing Program leakage test. At this time the applicable leakage limits must be met. Compliance with this LCO will ensure a primary containment configuration, including equipment hatches, that is structurally sound and that will limit leakage to those leakage rates assumed in the safety analyses.

Individual leakage rates for the primary containment air locks are addressed in LCO 3.6.1.2 and specified in the Primary Containment Leakage Rate Testing Program.

APPLICABILITY In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of (continued)

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Primary Containment B 3.6.1.1 BASES APPLICABILITY these MODES. Therefore, primary containment is not required (continued) to be OPERABLE in MODES 4 and 5 to prevent leakage of radioactive material from primary containment.

ACTIONS A.1 In the event primary containment is inoperable, primary containment must be restored to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining primary containment OPERABILITY during MODES 1, 2, and 3. This time period also ensures that the probability of an accident (requiring primary containment OPERABILITY) occurring during periods where primary containment is inoperable is minimal.

B.1 and B.2 If primary containment cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours0.5 days 0.0714 weeks 0.0164 months and to MODE 4 within 36 hours1.5 days 0.214 weeks 0.0493 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.1.1.1 REQUIREMENTS Maintaining the primary containment OPERABLE requires compliance with the visual examinations and leakage rate test requirements of the Primary Containment Leakage Rate Testing Program. Failure to meet the air lock leakage limit (SR 3.6.1.2.1), or the main steam isolation valve leakage limit (SR 3.6.1.3.10) does not necessarily result in a failure of this SR. The impact of the failure to meet these SRs must be evaluated against the Type A, B, and C acceptance criteria of the Primary Containment Leakage Rate Testing Program. Failure to meet the Low Pressure Coolant Injection (LPCI) or Core Spray (CS)System injection line air operated testable check valve leakage limit (SR 3.6.1.3.11) does not result in failure of this SR since the LPCI and CS testable check valve leakage is not included in the Primary Containment Leakage Rate Testing Program limits (Ref. 5 and 6).

(continued)

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Primary Containment B 3.6.1.1 BASES SURVEILLANCE SR 3.6.1.1.1 (continued)

REQUIREMENTS As left leakage, prior to startup after performing a required Primary Containment Leakage Rate Testing Program leakage test, is required to be

0.6 L for combined Type B and C leakage, and g 0.75 La for overalf Type A leakage. At all other times between required leakage rate tests, the acceptance criteria is based on an overall Type A leakage limit of : 1.0 La. At

1.0 La the offsite dose consequences are bounded by the assumptions of the safety analysis. The Frequency is required by the Primary Containment Leakage Rate Testing Program.

SR 3.6.1.1.2 Maintaining the pressure suppression function of primary containment requires limiting the leakage from the drywell to the suppression chamber. Thus, if an event were to occur that pressurized the drywell, the steam would be directed through the downcomers into the suppression pool. This SR is a leak test that confirms that the bypass area between the drywell and suppression chamber is less than the equivalent of a one inch diameter plate orifice (Ref. 1).

This ensures that the leakage paths that would bypass the suppression pool are within allowable limits (i.e.,

g 71 scfm).

Satisfactory performance of this SR can be achieved by establishing a known differential pressure between the drywell and the suppression chamber (; 1 psi)and verifying that the pressure in the suppression chamber does not increase by more than 0.25 inches of water per minute over a 10 minute period. The leakage test is performed every 24 months. The 24 month Frequency was developed considering the fact that component failures that might have affected this test are identified by other primary containment SRs.

Two consecutive test failures, however, would indicate unexpected primary containment degradation; in this event, as the Note indicates, increasing the Frequency to once every 12 months is required until the situation is remedied as evidenced by passing two consecutive tests.

REFERENCES 1. UFSAR, Section 5.2.

2. UFSAR, Section 14.6.1.3.

3. 10 CFR 50, Appendix J, Option B.

(continued)

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Primary Containment B 3.6.1.1_

BASES REFERENCES 4. 10 CFR 50.36(c)(2)(ii).

(continued)

5. License Amendment 40, dated November 9, 1978.

6. License Amendment 234, dated October 4, 1996.

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Primary Containment Air Locks B 3.6.1.a B 3.6 CONTAINMENT SYSTEMS B 3.6.1.2 Primary Containment Air Locks BASES BACKGROUND Two double door primary containment air locks (personnel access hatch and emergency escape hatch) have been built into the primary containment to provide personnel access to the drywell and to provide primary containment isolation during the process of personnel entry and exit. The air locks are designed to withstand the same loads, temperatures, and peak design internal and external pressures as the primary containment (Ref. 1). As part of the primary containment, the air locks limit the release of radioactive material to the environment during normal plant operation and through a range of transients and accidents up to and including postulated Design Basis Accidents (DBAs).

Each air lock door has been designed and tested to certify its ability to withstand a pressure in excess of the maximum expected pressure following a DBA in primary containment.

Each of the personnel access hatch doors contains double gasketed seals and local leakage rate testing capability to ensure pressure integrity. To effect a leak tight seal, the air lock design uses pressure seated doors (i.e., an increase in primary containment internal pressure results in increased sealing force on each door).

Each air lock is nominally a right circular cylinder, with doors at each end that are interlocked to prevent simultaneous opening. The air locks are provided with limit switches on both doors in each airlock that provide control room indication of door position. During periods when primary containment is not required to be OPERABLE, the air lock interlock mechanism may be disabled, allowing both doors of an air lock to remain open for extended periods when frequent primary containment entry is necessary. Under some conditions, as allowed by this LCO, the primary containment may be accessed through the air lock when the interlock mechanism has failed, by manually performing the interlock function.

The primary containment air locks form part of the primary containment pressure boundary. As such, air lock integrity and leak tightness are essential for maintaining the primary containment leakage rate to within limits in the event of a DBA. Not maintaining air lock integrity or leak tightness may result in a leakage rate in excess of that assumed in the plant safety analysis.

(Eo-n-ti -nu ed)

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Primary Containment Air Locks B 3.6.1.2_

BASES (continued)

APPLICABLE The postulated DBA that results in the maximum release of SAFETY ANALYSES radioactive material within primary containment is a LOCA.

In the analysis of this accident, it is assumed that primary containment is OPERABLE, such that release of fission products to the environment is controlled by the rate of primary containment leakage. The maximum allowable leakage rate (La) for the primary containment is 1.5% by weight of the containment air per 24 hours1 days 0.143 weeks 0.0329 months at the design basis LOCA maximum peak containment pressure (Pa) of 45 psig (Primary Containment Leakage Rate Testing Program). This allowable leakage rate forms the basis for the acceptance criteria imposed on the SRs associated with the air locks.

Primary containment air lock OPERABILITY is also required to minimize the amount of fission product gases that may escape primary containment through the air lock and contaminate and pressurize the secondary containment.

The primary containment air locks satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii) (Ref. 2).

LCO As part of the primary containment pressure boundary, the air lock's safety function is related to control of containment leakage rates following a DBA. Thus, the air lock's structural integrity and leak tightness are essential to the successful mitigation of such an event.

The primary containment air locks are required to be OPERABLE. For the air lock to be considered OPERABLE, the air lock interlock mechanism must be OPERABLE, the air lock must be in compliance with the Type B air lock leakage test, and both air lock doors must be OPERABLE. The interlock allows only one air lock door to be opened at a time. This provision ensures that a gross breach of primary containment does not exist when primary containment is required to be OPERABLE. Closure of a single door in each air lock is sufficient to provide a leak tight barrier following postulated events. Nevertheless, both doors are kept closed when the air lock is not being used for normal entry into or exit from primary containment.

APPLICABILITY In MODES 1. 2, and 3, a DBA could cause a release of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, the primary containment air locks are not required to be OPERABLE in MODES 4 and 5 to prevent leakage of radioactive material from primary containment.

(continued)

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Primary Containment Air Locks B 3.6.1.a BASES (continued)

ACTIONS The ACTIONS are modified by Note 1, which allows entry and exit to perform repairs of the affected air lock component.

If the outer door is inoperable, then it may be easily accessed for most repairs. It is preferred that the air lock be accessed from inside primary containment by entering through the other OPERABLE air lock. However, if this is not practicable, or if repairs on either door must be performed from the barrel side of the door, it is permissible to enter the air lock through the OPERABLE door, which means there is a short time during which the primary containment boundary is not intact (during access through the OPERABLE outer door). The allowance to open the OPERABLE door, even if it means the primary containment boundary is temporarily not intact, is acceptable due to the low probability of an event that could pressurize the primary containment during the short time in which the OPERABLE door is expected to be open. After each entry and exit, the OPERABLE door must be immediately closed .

Note 2 has been included to provide clarification that, for this LCO, separate Condition entry is allowed for each air lock. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable air lock. Complying with the Required Actions may allow for continued operation, and a subsequent inoperable air lock is governed by subsequent Condition entry and application of associated Required Actions.

The ACTIONS are modified by a third Note, which ensures appropriate remedial measures are taken when necessary, if air lock leakage results in exceeding overall containment leakage rate acceptance criteria. Pursuant to LCO 3.0.6, ACTIONS are not required even if primary containment leakage is exceeding L Therefore, the Note is added to require ACTIONS for LCO 3.6.1.1, "Primary Containment," to be taken in this event.

A.1, A.2, and A.3 With one primary containment air lock door inoperable in one or more primary containment air locks, the OPERABLE door in each affected air lock must be verified closed (Required Action A.1). This ensures that a leak tight primary containment barrier is maintained by the use of an OPERABLE air lock door. This action must be completed within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is consistent with the ACTIONS of LCO 3.6.1.1, which requires that primary containment be restored to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

(continued)

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Primary Containment Air Locks B 3.6.1.2 BASES ACTIONS A.1, A.2, and A.3 (continued)

In addition, the affected air lock penetration must be isolated by locking closed the OPERABLE air lock door within the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is considered reasonable for locking the OPERABLE air lock door, considering the OPERABLE door of the affected air lock is being maintained closed.

Required Action A.3 ensures that the affected air lock penetration has been isolated by the use of a locked closed OPERABLE air lock door. This ensures that an acceptable primary containment leakage boundary is maintained. The Completion Time of once per 31 days is based on engineering judgment and is considered adequate given the low likelihood of a locked door being mispositioned and other administrative controls. Required Action A.3 is modified by a Note that applies to air lock doors located in high radiation areas or areas with limited access due to inerting and allows these doors to be verified locked closed by use of administrative controls. Allowing verification by administrative controls is considered acceptable, since access to these areas is typically restricted. Therefore, the probability of misalignment of the door, once it has been verified to be in the proper position, is small.

The Required Actions have been modified by two Notes.

Note 1 ensures that only the Required Actions and associated Completion Times of Condition C are required if both doors in the air lock are inoperable. With both doors in the air lock inoperable, an OPERABLE door is not available to be closed. Required Actions C.1 and C.2 are the appropriate remedial actions. The exception of Note 1 does not affect tracking the Completion Time from the initial entry into Condition A; only the requirement to comply with the Required Actions. Note 2 allows use of the affected air lock for entry and exit for 7 days under administrative controls.

Primary containment entry may be required to perform Technical Specifications (TS) Surveillances and Required Actions, as well as other activities inside primary containment that are required by TS or activities that support TS-required equipment. This Note is not intended to preclude performing other activities (i.e., non-TS-related activities) if the primary containment was entered, using the inoperable air lock, to perform an allowed activity listed above. The required administrative controls consist of stationing a dedicated individual to assure closure of (continued)

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Primary Containment Air Locks B 3.6.1.2 BASES ACTIONS A.1, A.2, and A.3 (continued) the OPERABLE door except during the entry and exit, and to assure the OPERABLE door is relocked after completion of the containment entry and exit. This allowance is acceptable due to the low probability of an event that could pressurize the primary containment during the short time that the OPERABLE door is expected to be open.

B.1, B.2, and B.3 With an air lock interlock mechanism inoperable in one or both primary containment air locks, the Required Actions and associated Completion Times are consistent with those specified in Condition A.

The Required Actions have been modified by two Notes.

Note 1 ensures that only the Required Actions and associated Completion Times of Condition C are required if both doors in the same air lock are inoperable. With both doors in the same air lock inoperable, an OPERABLE door is not available to be closed. Required Actions C.1 and C.2 are the appropriate remedial actions. Note 2 allows entry into and exit from the primary containment under the control of a dedicated individual stationed at the air lock to ensure that only one door is opened at a time (i.e., the individual performs the function of the interlock).

Required Action B.3 is modified by a Note that applies to air lock doors located in high radiation areas or areas with limited access due to inerting and allows these doors to be verified locked closed by use of administrative controls.

Allowing verification by administrative controls is considered acceptable, since access to these areas is typically restricted. Therefore, the probability of misalignment of the door, once it has been verified to be in the proper position, is small.

C.1, C.2, and C.3 With one or more air locks inoperable for reasons other than those described in Condition A or B, Required Action C.1 requires action to be immediately initiated to evaluate containment overall leakage rates using current air lock leakage test results. An evaluation is acceptable since it is overly conservative to immediately declare the primary containment inoperable if both doors in an air lock have (continued)

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Primary Containment Air Locks B 3.6.1.2 BASES ACTIONS C.1, C.2, and C.3 (continued) failed a seal test or if the overall air lock leakage is not within limits. In many instances (e.g., only one seal per door has failed) primary containment remains OPERABLE, yet only 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months (according to LCO 3.6.1.1) would be provided to restore the air lock door to OPERABLE status prior to requiring a plant shutdown. In addition, even with both doors failing the seal test, the overall containment leakage rate can still be within limits.

Required Action C.2 requires that one door in the affected primary containment air locks must be verified closed. This Required Action must be completed within the 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time. This specified time period is consistent with the ACTIONS of LCO 3.6.1.1, which require that primary containment be restored to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

Additionally, the air lock must be restored to OPERABLE status within 24 hours1 days 0.143 weeks 0.0329 months (Required Action C.3). The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is reasonable for restoring an inoperable air lock to OPERABLE status considering that at least one door is maintained closed in each affected air lock.

D.1 and D.2 If the inoperable primary containment air lock cannot be restored to OPERABLE status within the associated Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours0.5 days 0.0714 weeks 0.0164 months and to MODE 4 within 36 hours1.5 days 0.214 weeks 0.0493 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.1.2.1 REQUIREMENTS Maintaining primary containment air locks OPERABLE requires compliance with the leakage rate test requirements of the Primary Containment Leakage Rate Testing Program. This SR reflects the leakage rate testing requirements with regard to air lock leakage (Type B leakage tests). The acceptance criteria were approved in License Amendment 97 (Ref. 3).

Subsequently, License Amendment 261 (Ref. 4) allowed an increased overall air lock leakage rate (i.e., Amendment 261 increased the value of La; therefore, the overall air lock (continued)

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Primary Containment Air Locks B 3.6.1.2.

BASES SURVEILLANCE SR 3.6.1.2.1 (continued)

REQUIREMENTS leakage rate limit value that corresponds to 0.05 La increased). The periodic testing requirements verify that the air lock leakage does not exceed the allowed fraction of the overall primary containment leakage rate. The Frequency is required by the Primary Containment Leakage Rate Testing Program.

The SR has been modified by two Notes. Note 1 states that an inoperable air lock door does not invalidate the previous successful performance of the overall air lock leakage test.

This is considered reasonable since either air lock door is capable of providing a fission product barrier in the event of a DBA. Note 2 has been added to this SR, requiring the results to be evaluated against the acceptance criteria which is applicable to SR 3.6.1.1.1 (Primary Containment Leakage Rate Testing Program). This ensures that air lock leakage is properly accounted for in determining the combined Type B and C primary containment leakage rate.

SR 3.6.1.2.2 The air lock interlock mechanism is designed to prevent simultaneous opening of both doors in the air lock. Since both the inner and outer doors of an air lock are designed to withstand the maximum expected post accident primary containment pressure (Ref. 1), closure of either door will support primary containment OPERABILITY. Thus, the interlock feature supports primary containment OPERABILITY while the air lock is being used for personnel transit in and out of the containment. Periodic testing of this interlock demonstrates that the interlock will function as designed and that simultaneous inner and outer door opening will not inadvertently occur. Due to the purely mechanical nature of this interlock, and given that the interlock mechanism is not normally challenged when primary containment air lock is used for entry and exit (procedures require strict adherence to single door opening), this test is only required to be performed every 24 months. The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage, and the potential for loss of primary containment OPERABILITY if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency. The 24 month Frequency is based on engineering judgment and is considered adequate given that the interlock is not challenged during use of the air lock.

(continued)

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Primary Containment Air Locks B 3.6.1.2 BASES (continued)

REFERENCES 1. UFSAR, Section 5.2.

3. NRC letter dated November 21, 1985, Issuance of Amendment 97 to the Facility Operating License DPR-59 for James A. FitzPatrick Nuclear Power Plant.

4. NRC letter dated April 21, 2000, Issuance of Amendment 261 to the Facility Operating License DPR-59 for James A. FitzPatrick Nuclear Power Plant.

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PCIVs B 3.6.1.3 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.3 Primary Containment Isolation Valves (PCIVs)

BASES BACKGROUND The function of the PCIVs, in combination with other accident mitigation systems, is to limit fission product release during and following postulated Design Basis Accidents (DBAs) to within limits. Primary containment isolation within the time limits specified for those isolation valves designed to close automatically ensures that the release of radioactive material to the environment will be consistent with the assumptions used in the analyses for a DBA.

The OPERABILITY requirements for PCIVs help ensure that an adequate primary containment boundary is maintained during and after an accident by minimizing potential paths to the environment. Therefore, the OPERABILITY requirements provide assurance that primary containment function assumed in the safety analyses will be maintained. These isolation devices are either passive or active (automatic). Manual valves, de-activated automatic valves secured in their closed position (including check valves with flow through the valve secured), blind flanges and closed systems are considered passive devices. Check valves, and other automatic valves designed to close without operator action following an accident, are considered active devices. One or more barriers are provided for each penetration so that no single credible failure or malfunction of an active component can result in a loss of isolation or leakage that exceeds limits assumed in the safety analyses. When two or more barriers are provided, one of these barriers may be a closed system.

The reactor building-to-suppression chamber vacuum breakers serve a dual function, one of which is primary containment isolation. However, since the other safety function of the vacuum breakers would not be available if the normal PCIV actions were taken, the PCIV OPERABILITY requirements are not applicable to the reactor building-to-suppression chamber vacuum breakers valves. Similar surveillance requirements in the LCO for reactor building-to-suppression chamber vacuum breakers provide assurance that the isolation capability is available without conflicting with the vacuum relief function.

(continued)

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PCIVs B 3.6.1.3_

BASES BACKGROUND The primary containment suppression chamber and drywell vent (continued) and purge lines are 20 and 24 inches in diameter respectively, and are normally maintained closed in MODES 1, 2, and 3 to ensure the primary containment boundary is maintained. The isolation valves on both the suppression chamber and drywell vent lines have 2 inch bypass lines around them for use during normal reactor operation or when it is not necessary to open the 20 and 24 inch valves. The only primary containment vent path provided, by design, is from the common 30 inch suppression chamber and drywell vent line through two parallel lines with valves (one 6 inches in diameter, the other 12 inches in diameter) to the 24 inch Standby Gas Treatment (SGT) System suction line. When in MODES 1, 2, and 3 only the low-flow 6 inch line (with valve 27MOV-121) is allowed to be open whenever the 20 or 24 inch vent and purge valves are open. The full-flow 12 inch line (with valve 27MOV-120) is required to be closed to prevent high pressure from reaching the SGT System filter trains in the unlikely event of a loss of coolant accident (LOCA) during venting. Closure of these valves will not prevent the SGT System from performing its design function (that is, to maintain a negative pressure in the secondary containment).

APPLICABLE The PCIV LCO was derived from the assumptions related to SAFETY ANALYSES minimizing the loss of reactor coolant inventory, and establishing the primary containment boundary during major accidents. As part of the primary containment boundary, PCIV OPERABILITY supports leak tightness of primary containment. Therefore, the safety analysis of any event requiring isolation of primary containment is applicable to this LCO.

The DBAs that result in a release of radioactive material for which the consequences are mitigated by PCIVs are a LOCA, control rod drop accident, and a main steam line break (MSLB). In the analysis for each of these accidents, it is assumed that PCIVs are either closed or close within the required isolation times following event initiation. This ensures that potential paths to the environment through PCIVs (including primary containment vent and purge valves) are minimized. Of the events analyzed in Reference 1 for which the consequences are mitigated by PCIVs, the MSLB is the most limiting event due to radiological consequences to control room personnel. The closure time of the main steam isolation valves (MSIVs) is a significant variable from a radiological standpoint. The MSIVs are required to close within 3 to 5 seconds, after signal generation, since the (continued)

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PCIVs B 3.6.1.3_

BASES APPLICABLE 3 second closure time is assumed in the MSIV closure analysis (Ref. 2) and the 5 second closure time is consistent with or conservative to the times assumed in the MSLB analyses (Refs. 3 and 4). Likewise, it is assumed that the primary containment is isolated such that release of fission products to the environment is controlled.

The DBA analysis does not assume a specific closure time for primary containment isolation valves (PCIVs). The analysis assumes that the leakage from the primary containment is 1.5 percent primary containment air weight per day (La) at pressure Pa throughout the accident. The bases for PCIV closure times, and the specified valve closure times, are specified in UFSAR Section 7.3.3.1 and UFSAR Table 7.3-1 (Refs. 5 and 6). respectively.

The single failure criterion required to be imposed in the conduct of plant safety analyses was considered in the original design of the primary containment vent and purge valves. Two valves in series on each vent and purge line provide assurance that both the supply and exhaust lines could be isolated even if a single failure occurred.

PCIVs satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii)

(Ref. 7).

LCO PCIVs form a part of the primary containment boundary. The PCIV safety function is related to minimizing the loss of reactor coolant inventory and establishing the primary containment boundary during a DBA.

The power operated, automatic isolation valves are required to have isolation times within limits and actuate on an automatic isolation signal. The 20 and 24 inch vent and purge valves must be maintained closed or blocked to prevent full opening. While the reactor building-to-suppression chamber vacuum breakers isolate primary containment penetrations, they are excluded from this Specification.

Controls on their isolation function are adequately addressed in LCO 3.6.1.6, "Reactor Building-to-Suppression Chamber Vacuum Breakers." The valves covered by this LCO are listed in Reference 8. The associated stroke time of each automatic PCIV is included in the Inservice Testing (IST) Program.

The normally closed PCIVs are considered OPERABLE when manual valves are closed or open in accordance with appropriate administrative controls, automatic valves are de-activated and secured in their closed position, blind (continued)

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BASES LCO flanges are in place, and closed systems are intact. These (continued) passive isolation valves and devices are those listed in Reference 8.

MSIVs, Low Pressure Coolant Injection (LPCI) and Core Spray (CS) System air operated testable check valves must meet additional leakage rate requirements. Other PCIV leakage rates are addressed by LCO 3.6.1.1, "Primary Containment,"

as Type B or C testing.

This LCO provides assurance that the PCIVs will perform their designed safety functions to minimize the loss of reactor coolant inventory and establish the primary containment boundary during accidents.

APPLICABILITY In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, most PCIVs are not required to be OPERABLE and the primary containment vent and purge valves are not required to be normally closed in MODES 4 and 5.

Certain valves, however, are required to be OPERABLE to prevent inadvertent reactor vessel draindown. These valves are those whose associated instrumentation is required to be OPERABLE per LCO 3.3.6.1, "Primary Containment Isolation Instrumentation." (This does not include the valves that isolate the associated instrumentation.)

ACTIONS The ACTIONS are modified by a Note allowing penetration flow path(s) to be unisolated intermittently under administrative controls. These controls consist of stationing a dedicated operator at the controls of the valve, who is in continuous communication with the control room. In this way, the penetration can be rapidly isolated when a need for primary containment isolation is indicated.

A second Note has been added to provide clarification that, for the purpose of this LCO, separate Condition entry is allowed for each penetration flow path. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable PCIV.

Complying with the Required Actions may allow for continued operation, and subsequent inoperable PCIVs are governed by subsequent Condition entry and application of associated Required Actions.

(continued)

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PCIVs B 3.6.1.3 BASES ACTIONS The ACTIONS are modified by Notes 3 and 4. Note 3 ensures that appropriate remedial actions are taken, if necessary, if the affected system(s) are rendered inoperable by an inoperable PCIV (e.g., an Emergency Core Cooling System subsystem is inoperable due to a failed open test return valve). Note 4 ensures appropriate remedial actions are taken when the primary containment leakage limits are exceeded. Pursuant to LCO 3.0.6, these actions are not required even when the associated LCO is not met.

Therefore, Notes 3 and 4 are added to require the proper actions be taken.

A.1 and A.2 With one or more penetration flow paths with one PCIV inoperable, except for inoperabilities due to MSIV leakage or LPCI or CS System air operated testable check valve leakage not within limit, the affected penetration flow paths must be isolated. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure.

Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, a blind flange, and a check valve with flow through the valve secured. For a penetration isolated in accordance with Required Action A.1, the device used to isolate the penetration should be the closest available valve to the primary containment. The Required Action must be completed within the 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time (8 hours0.333 days 0.0476 weeks 0.011 months for main steam lines). The Completion Time of 4 hours0.167 days 0.0238 weeks 0.00548 months is reasonable considering the time required to isolate the penetration and the relative importance of supporting primary containment OPERABILITY during MODES 1, 2, and 3. For main steam lines, an 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is allowed. The Completion Time of 8 hours0.333 days 0.0476 weeks 0.011 months for the main steam lines allows a period of time to restore the MSIVs to OPERABLE status given the fact that MSIV closure will result in isolation of the main steam line(s) and a potential for plant shutdown.

For affected penetrations that have been isolated in accordance with Required Action A.1, the affected penetration flow path(s) must be verified to be isolated on a periodic basis. This is necessary to ensure that primary containment penetrations required to be isolated following an accident, and no longer capable of being automatically isolated, will be in the isolation position should an event occur. This Required Action does not require any testing or (continued)

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PCIVs B 3.6.1.3 BASES ACTIONS A.1 and A.2 (continued) device manipulation. Rather, it involves verification that those devices outside containment and capable of potentially being mispositioned are in the correct position. The Completion Time of "once per 31 days for isolation devices outside primary containment" is appropriate because the devices are operated under administrative controls and the probability of their misalignment is low. For the devices inside primary containment, the time period specified "prior to entering MODE 2 or 3 from MODE 4, if primary containment was de-inerted while in MODE 4, if not performed within the previous 92 days" is based on engineering judgment and is considered reasonable in view of the inaccessibility of the devices and other administrative controls ensuring that device misalignment is an unlikely possibility.

Condition A is modified by a Note indicating that this Condition is only applicable to those penetration flow paths with two or more PCIVs. For penetration flow paths with one PCIV, Condition C provides the appropriate Required Actions.

Required Action A.2 is modified by two notes. Note 1 applies to isolation devices located in high radiation areas, and allows them to be verified by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted. Note 2 applies to the isolation devices that are locked, sealed, or otherwise secured in position and allows these devices to be verified closed by administrative means. Allowing verification by administrative means is considered acceptable, since the function of locking, sealing, or securing of components is to ensure that these devices are not inadvertently repositioned. Therefore, the probability of misalignment, once they have been verified to be in the proper position, is low.

B.1 With one or more penetration flow paths with two or more PCIVs inoperable except for inoperabilities due to MSIV leakage or LPCI or CS System air operated testable check valve leakage not within limits, either the inoperable PCIVs must be restored to OPERABLE status or the affected penetration flow path must be isolated within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a (continued)

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PCIVs B 3.6.1.3.

BASES ACTIONS B.1 (continued) single active component failure. Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, and a blind flange. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is consistent with the ACTIONS of LCO 3.6.1.1.

Condition B is modified by a Note indicating this Condition is only applicable to penetration flow paths with two or more PCIVs. For penetration flow paths with one PCIV, Condition C provides the appropriate Required Actions.

C.1 and C.2 With one or more penetration flow paths with one PCIV inoperable except for inoperabilities due to MSIV leakage or LPCI or CS System air operated testable check valve leakage not within limits, the inoperable valve must be restored to OPERABLE status or the affected penetration flow path must be isolated. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active component failure. Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, and a blind flange. A check valve may not be used to isolate the affected penetration. The Completion Time of 4 hours0.167 days 0.0238 weeks 0.00548 months is reasonable considering the time required to isolate the penetration and the relative importance of supporting primary containment OPERABILITY during MODES 1, 2, and 3.

The Completion Time of 72 hours3 days 0.429 weeks 0.0986 months for penetrations with a closed system is reasonable considering the relative stability of the closed system (hence, reliability) to act as a penetration isolation boundary and the relative importance of supporting primary containment OPERABILITY during MODES 1, 2, and 3. The closed system must meet the requirements of Reference 9. The Completion Time of 72 hours3 days 0.429 weeks 0.0986 months for EFCVs is also reasonable considering the instrument and the small pipe diameter of penetration (hence, reliability) to act as a penetration isolation boundary and the small pipe diameter of the affected penetrations. In the event the affected penetration flow path is isolated in accordance with Required Action C.1, the affected penetration must be verified to be isolated on a periodic basis. This is necessary to ensure that primary containment penetrations required to be isolated following an accident are isolated. This Required Action does not require any testing or device manipulation. Rather, it involves verification, that those devices outside (continued)

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BASES ACTIONS C.1 and C.2 (continued) containment and capable of potentially being mispositioned are in the correct position. The Completion Time of once per 31 days for verifying each affected penetration is isolated is appropriate because the valves are operated under administrative controls and the probability of their misalignment is low.

Condition C is modified by a Note indicating that this Condition is only applicable to penetration flow paths with only one PCIV. For penetration flow paths with two or more PCIVs, Conditions A and B provide the appropriate Required Actions.

Required Action C.2 is modified by two Notes. Note 1 applies to valves and blind flanges located in high radiation areas and allows them to be verified by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted. Note 2 applies to isolation devices that are locked, sealed, or otherwise secured in position and allows these devices to be verified closed by use of administrative means. Allowing verification by administrative means is considered acceptable, since the function of locking, sealing, or securing components is to ensure that these devices are not inadvertently repositioned. Therefore, the probability of misalignment, once they have been verified to be in the proper position, is low.

D.1 With any MSIV leakage rate not within limit, the assumptions of the safety analysis may not be met. Therefore, the leakage must be restored to within limit within 8 hours0.333 days 0.0476 weeks 0.011 months .

Restoration can be accomplished by isolating the penetration that caused the limit to be exceeded by use of one closed and de-activated automatic valve, closed manual valve, or blind flange. When a penetration is isolated, the leakage rate for the isolated penetration is assumed to be the actual pathway leakage through the isolation device. If two isolation devices are used to isolate the penetration, the leakage rate is assumed to be the lesser actual pathway leakage of the two devices. The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is reasonable considering the time required to restore the (continued)

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PCIVs B 3.6.1.3.

BASES ACTIONS D.1 (continued) leakage by isolating the penetration, the fact that MSIV closure will result in isolation of the main steam line(s) and a potential for plant shutdown, and the relative importance of MSIV leakage to the overall containment function.

E.1 With the one or more penetration flow paths with LPCI System or CS System air operated testable check valve leakage rate not within limits, the assumptions of the safety analysis may not be met. Therefore, the leakage must be restored to within limit within 72 hours3 days 0.429 weeks 0.0986 months . Restoration can be accomplished by isolating the penetration that caused the limit to be exceeded by use of one closed and de-activated automatic valve, or closed manual valve. When a penetration is isolated, the leakage rate for the isolated penetration is assumed to be the actual pathway leakage through the isolation device. If two isolation devices are used to isolate the penetration, the leakage rate is assumed to be the lesser actual pathway leakage of the two devices. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is reasonable considering the time required to restore the leakage and the importance to maintain these penetrations available to perform the required function during a design basis accident.

F.1 and F.2 If any Required Action and associated Completion Time cannot be met in MODE 1, 2, or 3, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours0.5 days 0.0714 weeks 0.0164 months and to MODE 4 within 36 hours1.5 days 0.214 weeks 0.0493 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

G.1 and G.2 If any Required Action and associated Completion Time cannot be met for PCIV(s) required to OPERABLE during MODE 4 or 5, the plant must be placed in a condition in which the LCO does not apply. Action must be immediately initiated to (continued)

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PCIVs B 3.6.1.3 BASES ACTIONS G.1 and G.2 (continued) suspend operations with a potential for draining the reactor vessel (OPDRVs) to minimize the probability of a vessel draindown and subsequent potential for fission product release. Actions must continue until OPDRVs are suspended and valve(s) are restored to OPERABLE status. If suspending an OPDRV would result in closing the residual heat removal (RHR) shutdown cooling isolation valves, an alternative Required Action is provided to immediately initiate action to restore the valve(s) to OPERABLE status. This allows RHR shutdown cooling to remain in service while actions are being taken to restore the valve.

SURVEILLANCE SR 3.6.1.3.1 REQUIREMENTS This SR ensures that the primary containment vent and purge valves are closed as required or, if open, open for an allowable reason. If a purge valve is open in violation of this SR, the valve is considered inoperable. The SR is modified by a Note stating that the SR is not required to be met when the vent and purge valves are open for the stated reasons. The Note states that these valves may be opened for inerting, de-inerting, pressure control, ALARA or air quality considerations for personnel entry, or Surveillances that require the valves to be open, provided the full-flow 12 inch line (with valve 27MOV-120) to the SGT System is closed and one or more SGT System reactor building suction valves are open. This will ensure there is no damage to the filters if a LOCA were to occur with the vent and purge valves open since excessive differential pressure is not expected with the full-flow 12 inch line closed and one or more SGT System reactor building suction valves open. The 20 and 24 inch vent and purge valves are capable of closing against the dynamic effects of a LOCA. Therefore, these valves are allowed to be open for limited periods of time.

The 31 day Frequency is consistent with other PCIV requirements discussed in SR 3.6.1.3.2.

SR 3.6.1.3.2 This SR ensures that each primary containment isolation manual valve and blind flange that is located outside primary containment and not locked, sealed or otherwise secured and is required to be closed during accident conditions is closed. The SR helps to ensure that post accident leakage of radioactive fluids or gases outside the primary containment boundary is within design limits.

(continued)

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PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.2 (continued)

REQUIREMENTS This SR does not require any testing or valve manipulation.

Rather, it involves verification that those isolation devices outside primary containment, and capable of being mispositioned, are in the correct position. Since verification of valve position for isolation devices outside primary containment is relatively easy, the 31 day Frequency was chosen to provide added assurance that the isolation devices are in the correct positions.

Two Notes have been added to this SR. The first Note allows valves and blind flanges located in high radiation areas to be verified by use of administrative controls. Allowing verification by administrative controls is considered acceptable since the primary containment is inerted and access to these areas is typically restricted during MODES 1, 2, and 3 for ALARA reasons. Therefore, the probability of misalignment of these isolation devices, once they have been verified to be in the proper position, is low. A second Note has been included to clarify that PCIVs that are open under administrative controls are not required to meet the SR during the time that the PCIVs are open.

These controls consist of stationing a dedicated operator at the controls of the valve, who is in continuous communication with the control room. In this way, the penetration can be rapidly isolated when a need for primary containment isolation is indicated. This SR does not apply to valves that are locked, sealed, or otherwise secured in the closed position, since these were verified to be in the correct position upon locking, sealing, or securing.

SR 3.6.1.3.3 This SR ensures that each primary containment manual isolation valve and blind flange that is located inside primary containment and not locked, sealed or otherwise secured and is required to be closed during accident conditions is closed. The SR helps to ensure that post accident leakage of radioactive fluids or gases outside the primary containment boundary is within design limits. For isolation devices inside primary containment, the Frequency defined as "prior to entering MODE 2 or 3 from MODE 4 if primary containment was de-inerted while in MODE 4, if not performed within the previous 92 days" is appropriate since these isolation devices are operated under administrative controls and the probability of their misalignment is low.

This SR does not apply to valves that are locked, sealed, or (continued)

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PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.3 (continued)

REQUIREMENTS otherwise secured in the closed position, since these were verified to be in the correct position upon locking, sealing, or securing.

Two Notes have been added to this SR. The first Note allows valves and blind flanges located in high radiation areas to be verified by use of administrative controls. Allowing verification by administrative controls is considered acceptable since the primary containment is inerted and access to these areas is typically restricted during MODES 1, 2, and 3 for ALARA reasons. Therefore, the probability of misalignment of these isolation devices, once they have been verified to be in their proper position, is low. A second Note has been included to clarify that PCIVs that are open under administrative controls are not required to meet the SR during the time that the PCIVs are open.

These controls consist of stationing a dedicated operator at the controls of the valve, who is in continuous communication with the control room. In this way, the penetration can be rapidly isolated when a need for primary containment isolation is indicated.

SR 3.6.1.3.4 The traversing incore probe (TIP) shear isolation valves are actuated by explosive charges. Surveillance of explosive charge continuity provides assurance that TIP valves will actuate when required. Other administrative controls, such as those that limit the shelf life of the explosive charges, must be followed. The 31 day Frequency is based on operating experience that has demonstrated the reliability of the explosive charge continuity.

SR 3.6.1.3.5 Verifying the isolation time of each power operated, automatic PCIV is within limits is required to demonstrate OPERABILITY. MSIVs may be excluded from this SR since MSIV full closure isolation time is demonstrated by SR 3.6.1.3.6.

The isolation time test ensures that the valve will isolate in a time period less than or equal to that assumed in the safety analyses. The Frequency of this SR is in accordance with the requirements of the Inservice Testing Program.

(continued)

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BASES SURVEILLANCE SR 3.6.1.3.6 REQUIREMENTS (continued) Verifying that the isolation time of each MSIV is within the specified limits is required to demonstrate OPERABILITY.

The isolation time test ensures that the MSIV will isolate in a time period that does not exceed the times assumed in the DBA analyses. This ensures that the calculated radiological consequences of these events remain within 10 CFR 100 limits. The Frequency of this SR is in accordance with the requirements of the Inservice Testing Program.

SR 3.6.1.3.7 Automatic PCIVs close on a primary containment isolation signal to prevent leakage of radioactive material from primary containment following a DBA. This SR ensures that each automatic PCIV will actuate to its isolation position on a primary containment isolation signal. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.6.1, "Primary Containment Isolation Instrumentation," overlaps this SR to provide complete testing of the safety function. The 24 month Frequency was developed considering it is prudent that this Surveillance be performed only during a plant outage since isolation of penetrations would eliminate cooling water flow and disrupt the normal operation of many critical components. Operating experience has shown that these components usually pass this Surveillance when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

SR 3.6.1.3.8 This SR requires a demonstration that each reactor instrumentation line excess flow check valve (EFCV) is OPERABLE by verifying that the valve actuates to the isolation position on a simulated instrument line break.

This SR provides assurance that the instrumentation line EFCVs will perform so that secondary containment will not be overpressurized during the postulated instrument line break (Ref. 10). The Frequency of this SR is in accordance with the requirements of the Inservice Testing Program.

(continued)

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PCIVs B 3.6.1. 3 BASES SURVEILLANCE SR 3.6.1.3.9 REQUIREMENTS (continued) The TIP shear isolation valves are actuated by explosive charges. An in-place functional test is not possible with this design. The explosive squib is removed and tested to provide assurance that the valves will actuate when required. The replacement charge for the explosive squib shall be from the same manufactured batch as the one fired or from another batch that has been certified by having one of the batch successfully fired. The Frequency of 24 months on a STAGGERED TEST BASIS is considered adequate given the administrative controls on replacement charges and the frequent checks of circuit continuity (SR 3.6.1.3.4).

SR 3.6.1.3.10 The analyses in Reference 11 are based on leakage that is more than the specified leakage rate. Leakage through each MSIV must be g 11.5 scfh when tested at 2 25 psig. This ensures that MSIV leakage is properly accounted for in determining the overall primary containment leakage rate.

The Frequency is in accordance with the Primary Containment Leakage Rate Testing Program.

SR 3.6.1.3.11 Surveillance of each air operated testable check valve associated with the LPCI and CS Systems vessel injection penetrations provides assurance that the resulting radiation dose rate that would result if the reactor coolant were released to the reactor building at the specified limit will be small (Ref. 12). The acceptance criteria for each air operated testable check valve associated with the LPCI and CS Systems vessel injection penetrations is < 10 gpm when hydrostatically tested at ; 1035 psig or < 10 scfm when pneumatically tested at 2 45 psig, at ambient temperature (Ref. 12). The leakage rates must be demonstrated in accordance with the leakage rate test Frequency required by the Primary Containment Leakage Rate Testing Program.

REFERENCES 1. UFSAR, Section 14.6.

2. UFSAR, Section 14.5.2.3.

3. UFSAR, Section 6.5.3.2.

4. UFSAR, Section 14.8.2.1.2.

(continued)

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PCIVs B 3.6.1.31 BASES REFERENCES 5. UFSAR, Section 7.3.3.1.

(continued)

6. UFSAR, Table 7.3-1.

7. 10 CFR 50.36(c)(2)(ii).

8. Technical Requirements Manual.

9. UFSAR, Section 5.2.3.5.

10. UFSAR, Section 16.3.2.5.

11. UFSAR, Section 14.8.2.1.1.

12. NRC Letter to NYPA, November 9, 1978 NRC Safety Evaluation Supporting Amendment 40 to the Facility Operating License No. DPR-59.

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Drywell Pressure B 3.6.1.4-B 3.6 CONTAINMENT SYSTEMS B 3.6.1.4 Drywell Pressure BASES BACKGROUND The drywell pressure is limited during normal operations to preserve the initial conditions assumed in the accident analysis for a Design Basis Accident (DBA) or loss of coolant accident (LOCA).

APPLICABLE Primary containment performance is evaluated for the entire SAFETY ANALYSES spectrum of break sizes for postulated LOCAs (Ref. 1).

Among the inputs to the DBA is the initial primary containment internal pressure (Refs. 1, 2 and 3). Analyses assume an initial drywell pressure of 1.95 psig. This limitation ensures that the safety analysis remains valid by maintaining the expected initial conditions and ensures that the peak LOCA drywell internal pressure does not exceed the drywell design pressure of 56 psig.

The maximum calculated drywell pressure occurs during the reactor blowdown phase of the DBA, which assumes an instantaneous recirculation line break. The calculated peak drywell pressure for this limiting event is 41.2 psig (Ref. 4).

Drywell pressure satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii) (Ref. 5).

LCO In the event of a DBA, with an initial drywell pressure

- 1.95 psig, the resultant peak drywell accident pressure will be maintained below the maximum allowable drywell pressure.

APPLICABILITY In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, maintaining drywell pressure within limits is not required in MODE 4 or 5.

ACTIONS A.1 With drywell pressure not within the limit of the LCO, drywell pressure must be restored within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The Required Action is necessary to return operation to within (continued)

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Drywell Pressure B 3.6.1.4_

BASES ACTIONS A.1 (continued) the bounds of the primary containment analysis. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is consistent with the ACTIONS of LCO 3.6.1.1, "Primary Containment," which requires that primary containment be restored to OPERABLE status within I hour.

B.1 and B.2 If drywell pressure cannot be restored to within limit within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours0.5 days 0.0714 weeks 0.0164 months and to MODE 4 within 36 hours1.5 days 0.214 weeks 0.0493 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.1.4.1 REQUIREMENTS Verifying that drywell pressure is within limit ensures that plant operation remains within the limit assumed in the primary containment analysis. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency of this SR was developed, based on operating experience related to trending of drywell pressure variations during the applicable MODES. Furthermore, the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal drywell pressure condition.

REFERENCES 1. UFSAR, Section 14.6.1.3.3.

2. NEDO-24578, Revision 0, Mark I Containment Program Plant Unique Load Definition, James A. FitzPatrick Nuclear Power Plant, March 1979.

3. UFSAR, Section 16.9.3.5.

4. UFSAR, Section 16.9.3.5.1.3.

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Drywell Air Temperature B 3.6.1.5-B 3.6 CONTAINMENT SYSTEMS B 3.6.1.5 Drywell Air Temperature BASES BACKGROUND The drywell contains the reactor vessel and piping, which add heat to the airspace. Drywell coolers remove heat and maintain a suitable environment. The average airspace temperature affects the calculated response to postulated Design Basis Accidents (DBAs). The limitation on the drywell average air temperature was developed as reasonable, based on operating experience. The limitation on drywell air temperature is used in the Reference 1 safety analyses.

APPLICABLE Primary containment performance is evaluated for a SAFETY ANALYSES spectrum of break sizes for postulated loss of coolant accidents (LOCAs) (Ref. 1). Among the inputs to the design basis analysis is the initial drywell average air temperature (Refs. 1 and 2). Analyses assume an initial average drywell air temperature of 135 0 F. This limitation ensures that the safety analysis remains valid by maintaining the expected initial conditions and ensures that the peak LOCA drywell temperature and pressure do not exceed the drywell design pressure of 56 psig coincident with a design temperature of 309°F (Ref. 3). Exceeding these design limitations may result in the degradation of the primary containment structure under accident loads.

Equipment inside primary containment required to mitigate the effects of a DBA is designed to operate and be capable of operating under environmental conditions expected for the spectrum of break sizes.

Drywell air temperature satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii) (Ref. 4).

LCO In the event of a DBA, with an initial drywell average air temperature less than or equal to the LCO temperature limit, the resultant peak accident temperature and pressure are maintained within the drywell design limits and within the environmental qualification envelope of the equipment in the drywell. As a result, the ability of primary containment to perform its design function is ensured.

APPLICABILITY In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences of these events are (continued)

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Drywell Air Temperature B 3.6.1.5_

BASES APPLICABILITY reduced due to the pressure and temperature limitations of (continued) these MODES. Therefore, maintaining drywell average air temperature within the limit is not required in MODE 4 or 5.

ACTIONS A.1 With drywell average air temperature not within the limit of the LCO, drywell average air temperature must be restored within 8 hours0.333 days 0.0476 weeks 0.011 months . The Required Action is necessary to return operation to within the bounds of the primary containment analysis. The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is acceptable.

considering the sensitivity of the analysis to variations in this parameter, and provides sufficient time to correct minor problems.

B.1 and B.2 If the drywell average air temperature cannot be restored to within the limit within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours0.5 days 0.0714 weeks 0.0164 months and to MODE 4 within 36 hours1.5 days 0.214 weeks 0.0493 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.1.5.1 REQUIREMENTS Verifying that the drywell average air temperature is within the LCO limit ensures that operation remains within the limits assumed for the primary containment analyses.

Drywell air temperature is monitored in various areas and at various elevations (referenced to mean sea level). Due to the shape of the drywell, a volumetric average is used to determine an accurate representation of the actual average temperature.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency of the SR was developed based on operating experience related to drywell average air temperature variations and temperature instrument drift during the applicable MODES and the low probability of a DBA occurring between surveillances. Furthermore, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is considered adequate in view of other (continued)

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Drywell Air Temperature B 3.6.1.5_

BASES SURVEILLANCE SR 3.6.1.5.1 (continued)

REQUIREMENTS indications available in the control room, including alarms, to alert the operator to an abnormal drywell air temperature condition.

REFERENCES 1. UFSAR, Section 14.6.1.3.3.

2. GE-NE-T23-00737-01, James A. FitzPatrick Nuclear Power Plant Higher RHR Service Water Temperature Analysis, August 1996.

3. UFSAR, 16.7.3.2.3.

JAFNPP B 3.6.1.5-3 Revision 0

Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.6 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.6 Reactor Building-to-Suppression Chamber Vacuum Breakers BASES BACKGROUND The function of the reactor building-to-suppression chamber vacuum breakers is to relieve vacuum when primary containment depressurizes below reactor building pressure.

If the drywell depressurizes below reactor building pressure, the negative differential pressure is mitigated by flow through the reactor building-to-suppression chamber vacuum breakers and through the suppression-chamber-to drywell vacuum breakers. The design of the reactor building-to-suppression chamber vacuum relief system consists of four vacuum breakers (two parallel sets of 100%

capacity vacuum breaker pairs, each set consisting of a self-actuating vacuum breaker and an air operated vacuum breaker), located in two lines. The air operated vacuum breakers are actuated by differential pressure switches and can be remotely operated from the relay room. The self actuating vacuum breakers function similar to a check valve.

The two vacuum breakers in series must be closed to maintain a leak tight primary containment boundary.

A negative differential pressure across the drywell wall is caused by rapid depressurization of the drywell. Events that cause this rapid depressurization are cooling cycles, inadvertent primary containment spray actuation, and steam condensation in the event of a primary system rupture.

Reactor building-to-suppression chamber vacuum breakers prevent an excessive negative differential pressure across the primary containment boundary. Cooling cycles result in minor pressure transients in the drywell, which occur slowly and are normally controlled by ventilation equipment.

Inadvertent spray actuation results in a more significant negative pressure transient.

The reactor building-to-suppression chamber vacuum breakers are sized to mitigate any depressurization transient and limit the maximum negative containment (drywell and suppression chamber) pressure to within design limits. The maximum depressurization rate is a function of the primary containment spray flow rate and temperature and the assumed initial conditions of the primary containment atmosphere.

Low spray temperatures and atmospheric conditions that yield the minimum amount of contained noncondensible gases are assumed for conservatism.

(Eo-nt-i n-ued)

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Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.6_

BASES (continued)

APPLICABLE Suppression chamber-to-drywell and reactor building SAFETY ANALYSES to-suppression chamber vacuum breakers are provided as part of the primary containment to limit the negative differential pressure across the drywell and suppression chamber walls, which form part of the primary containment boundary.

The safety analyses assume the reactor building-to suppression chamber vacuum breakers to be closed initially (Ref. 1). Additionally, one or both reactor building-to suppression chamber vacuum breakers in each line are assumed to fail in a closed position. Therefore, the single active failure criterion is met.

Several cases were considered in the safety analyses to determine the maximum negative pressure differential between the containment and reactor building assuming the reactor building-to-suppression chamber vacuum breakers remain closed (Ref. 1):

a. A small break loss of coolant accident followed by actuation of one Residual Heat Removal (RHR) containment spray loop;

b. Inadvertent actuation of one RHR containment spray loop during normal operation;

c. A large break loss of coolant accident followed by actuation of one RHR containment spray loop.

The results of these cases show that the reactor building to-suppression chamber vacuum breakers are not required to mitigate the consequences of any DBA since the maximum resulting negative differential pressure is 1.92 psid (case a) which is below the design differential pressure limit of 2 psid. However, to ensure the resulting negative pressure is minimized, the reactor building-to-suppression chamber vacuum breakers are included in the design and set to ensure the valves start to open at . 0.5 psid.

The reactor building-to-suppression chamber vacuum breakers satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii) (Ref. 2).

LCO All reactor building-to-suppression chamber vacuum breakers are required to be OPERABLE to ensure the primary containment design differential pressure limit is not challenged. This requirement ensures both vacuum breakers in each line (self-actuated vacuum breaker and air operated (continued)

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Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.6.

BASES LCO vacuum breaker) will open to relieve a negative pressure in (continued) the suppression chamber. This LCO also ensures that the two vacuum breakers in each of the two lines from the reactor building to the suppression chamber airspace are closed (except during testing or when performing their intended function).

APPLICABILITY In MODES 1, 2, and 3, a DBA could result in excessive negative differential pressure across the drywell wall caused by the rapid depressurization of the drywell. The event that results in the limiting rapid depressurization of the drywell is the primary system rupture, which purges the drywell of air and fills the drywell free airspace with steam. Subsequent condensation of the steam would result in depressurization of the drywell, which after the suppression chamber-to-drywell vacuum breakers open (due to differential pressure between the suppression chamber and drywell) would result in depressurization of the suppression chamber. The limiting pressure and temperature of the primary system prior to a DBA occur in MODES 1, 2, and 3. Excessive negative pressure inside primary containment could also occur due to inadvertent initiation of the RHR Containment Spray System.

In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining reactor building-to-suppression chamber vacuum breakers OPERABLE is not required in MODE 4 or 5.

ACTIONS A Note has been added to provide clarification that, for the purpose of this LCO, separate Condition entry is allowed for each penetration flow path.

A.1 With one or more lines with one vacuum breaker not closed, the leak tight primary containment boundary may be threatened. Therefore, the inoperable vacuum breakers must be restored to OPERABLE status or the open vacuum breaker closed within 72 hours3 days 0.429 weeks 0.0986 months . The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is consistent with requirements for inoperable suppression chamber-to-drywell vacuum breakers in LCO 3.6.1.7, "Suppression-Chamber-to-Drywell Vacuum Breakers." The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the redundant capability afforded by the remaining breakers, the fact (continued)

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Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.6_

BASES ACTIONS A.1 (continued) that the OPERABLE breaker in each of the lines is closed, and the low probability of an event occurring that would require the vacuum breakers to be OPERABLE during this period.

B.1 With one or more lines with two vacuum breakers not closed, primary containment integrity is not maintained. Therefore, one open vacuum breaker must be closed within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . This Completion Time is consistent with the ACTIONS of LCO 3.6.1.1, "Primary Containment," which requires that primary containment be restored to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

C.1 With one line with one or more vacuum breakers inoperable for opening, the leak tight primary containment boundary is intact. The ability to mitigate the consequences of an event that causes a containment depressurization is threatened if one or more vacuum breakers in at least one vacuum breaker penetration are not OPERABLE. Therefore, the inoperable vacuum breaker must be restored to OPERABLE status within 72 hours3 days 0.429 weeks 0.0986 months . This is consistent with the Completion Time for Condition A and the fact that the leak tight primary containment boundary is being maintained.

D.1 With two lines with one or more vacuum breakers inoperable for opening, the primary containment boundary is intact.

However, in the event of a containment depressurization, the vacuum relief function of the vacuum breakers is lost.

Therefore, all vacuum breakers in one line must be restored to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . This Completion Time is consistent with the ACTIONS of LCO 3.6.1.1, which requires that primary containment be restored to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

(continued)

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Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.6_

BASES ACTIONS E.1 and E.2 (continued)

If any Required Action and associated Completion Time cannot be met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours0.5 days 0.0714 weeks 0.0164 months and to MODE 4 within 36 hours1.5 days 0.214 weeks 0.0493 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.1.6.1 REQUIREMENTS Each vacuum breaker is verified to be closed to ensure that a potential breach in the primary containment boundary is not present. This Surveillance may be performed by observing local or remote indications of vacuum breaker position. Position indications of the air operated vacuum breakers are available in the control and relay rooms while position indications of the self actuating vacuum breakers are only available in the relay room. The 14 day Frequency is based on engineering judgment, is considered adequate in view of other indications of vacuum breaker status available to operations personnel, and has been shown to be acceptable through operating experience.

Two Notes are added to this SR. The first Note allows reactor building-to-suppression chamber vacuum breakers opened in conjunction with the performance of a Surveillance to not be considered as failing this SR. These periods of opening vacuum breakers are controlled by plant procedures and do not represent inoperable vacuum breakers. The second Note is included to clarify that vacuum breakers open due to an actual differential pressure are not considered as failing this SR.

SR 3.6.1.6.2 Each vacuum breaker must be cycled to ensure that it opens properly to perform its design function and returns to its fully closed position. This ensures that the safety analysis assumptions are valid. The Frequency of this SR is in accordance with the Inservice Testing Program.

(continued)

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Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.6 BASES SURVEILLANCE SR 3.6.1.6.3 REQUIREMENTS (continued) A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.

The Frequency of SR 3.6.1.6.3 is based on the assumption of a 92 day calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

SR 3.6.1.6.4 Demonstration of each self-actuating vacuum breaker opening setpoint is necessary to ensure that the design function regarding vacuum breaker opening differential pressure of

0.5 psid is valid. While this Surveillance can be performed with the reactor at power, operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency, which is based on the operating cycle. The 24 month Frequency is further justified because SR 3.6.1.6.2 is performed at a shorter Frequency that conveys the proper functioning status of each self-actuating vacuum breaker.

REFERENCES 1. Design Bases Document-016A, Section 5.2.10, Maximum Design Negative Pressure for Containment.

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Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.7 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.7 Suppression Chamber-to-Drywell Vacuum Breakers BASES BACKGROUND The function of the suppression chamber-to-drywell vacuum breakers is to relieve vacuum in the drywell. There are 5 external vacuum breakers located on the external lines connecting the top of the suppression chamber with drywell vent pipes, which allow air and steam flow from the suppression chamber to the drywell when the drywell is at a negative pressure with respect to the suppression chamber.

Therefore, suppression chamber-to-drywell vacuum breakers prevent an excessive negative differential pressure across the wetwell drywell boundary. Each vacuum breaker is a self-actuating valve, similar to a check valve, which can be manually operated locally for testing purposes.

A negative differential pressure across the drywell wall is caused by rapid depressurization of the drywell. Events that cause this rapid depressurization are cooling cycles, drywell spray actuation, and steam condensation from sprays or subcooled reflood water in the event of a primary system rupture. Cooling cycles result in minor pressure transients in the drywell that occur slowly and are normally controlled by ventilation equipment. Spray actuation or the spilling of subcooled water out of a break results in more significant pressure transients and becomes important in sizing the suppression chamber-to-drywell vacuum breakers.

In the event of a primary system rupture, steam condensation within the drywell results in the most severe pressure transient. Following a primary system rupture, the gas mixture in the drywell is purged into the suppression chamber free airspace, leaving the drywell full of steam.

Subsequent condensation of the steam can be caused in two possible ways, namely, Emergency Core Cooling Systems flow out of a line break, or Residual Heat Removal (RHR)

Containment Spray System actuation following a loss of coolant accident (LOCA). These two cases determine the maximum depressurization rate of the drywell.

In addition, the waterleg in the Mark I Vent System downcomers are controlled by the drywell-to-suppression chamber differential pressure. If the drywell pressure is less than the suppression chamber pressure, there will be an increase in the vent waterleg. This will result in an increase in the water clearing inertia in the event of a postulated LOCA, resulting in an increase in the peak (continued)

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Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.7_

BASES BACKGROUND drywell pressure. This in turn will result in an increase (continued) in the pool swell dynamic loads. The suppression chamber to-drywell vacuum breakers may limit the height of the waterleg in the vent system during time periods when drywell-to-suppression chamber differential pressure is not required or is not maintained within the limits specified in LCO 3.6.2.4, "Drywell-to-Suppression Chamber Differential Pressure."

APPLICABLE Analytical methods and assumptions involving the SAFETY ANALYSES suppression chamber-to-drywell vacuum breakers are used as part of the accident analyses of the primary containment systems. Suppression chamber-to-drywell and reactor building-to-suppression chamber vacuum breakers are provided as part of the primary containment to limit the negative differential pressure across the drywell and suppression chamber walls that form part of the primary containment boundary.

The safety analyses assume that the suppression chamber-to drywell vacuum breakers are closed initially and start to open at a differential pressure of 0.5 psid (Refs. 1 and 2).

Additionally, 1 of the 5 vacuum breakers is assumed to fail in a closed position (Ref. 1). The results of the analyses show that the design differential pressure is not exceeded even under the worst case accident scenario. The vacuum breaker opening differential pressure setpoint and the requirement that all vacuum breakers be OPERABLE (the additional vacuum breaker is required to meet the single failure criterion) are a result of the requirement placed on the vacuum breakers to limit the vent system waterleg height. The cross sectional areas of the vacuum breakers are sized on the basis of the Bodega Bay pressure suppression system tests. The vacuum breaker capacity selected on this test basis is more than adequate to limit the pressure differential between the suppression chamber and drywell during post-accident drywell cooling operations to a value which is within the suppression system design values (Refs. 3 and 4). Design Basis Accident (DBA) analyses assume the vacuum breakers to be closed initially and to remain closed and leak tight, until the suppression pool is at a positive pressure relative to the drywell.

The suppression chamber-to-drywell vacuum breakers satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii) (Ref. 5).

(continued)

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Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.7_

BASES (continued)

LCO All vacuum breakers must be OPERABLE for opening. All suppression chamber-to-drywell vacuum breakers are also required to be closed (except during testing or when the vacuum breakers are performing their intended design function). The vacuum breaker OPERABILITY requirement provides assurance that the drywell-to-suppression chamber negative differential pressure remains below the design value. The requirement that the vacuum breakers be closed ensures that there is no excessive bypass leakage should a LOCA occur.

APPLICABILITY In MODES 1, 2, and 3, a DBA could result in excessive negative differential pressure across the drywell wall, caused by the rapid depressurization of the drywell. The event that results in the limiting rapid depressurization of the drywell is the primary system rupture that purges the drywell of air and fills the drywell free airspace with steam. Subsequent condensation of the steam would result in depressurization of the drywell. The limiting pressure and temperature of the primary system prior to a DBA occur in MODES 1, 2, and 3. Excessive negative pressure inside the drywell could also occur due to inadvertent actuation of the RHR Containment Spray System during normal operation.

In MODES 4 and 5, the probability and consequences of these events are reduced by the pressure and temperature limitations in these MODES; therefore, maintaining suppression chamber-to-drywell vacuum breakers OPERABLE is not required in MODE 4 or 5.

ACTIONS A.1 With one of the vacuum breakers inoperable for opening (e.g., the vacuum breaker is not open and may be stuck closed or not within its opening setpoint limit, so that it would not function as designed during an event that depressurized the drywell), the remaining four OPERABLE vacuum breakers are capable of providing the vacuum relief function. However, overall system reliability is reduced because a single active failure in one of the remaining vacuum breakers could result in an excessive negative drywell-to-suppression chamber differential pressure during a DBA. Therefore, with one of the five vacuum breakers inoperable, 72 hours3 days 0.429 weeks 0.0986 months is allowed to restore the inoperable vacuum breaker to OPERABLE status so that plant conditions (continued)

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Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.7 BASES ACTIONS A.1 (continued) are consistent with those assumed for the design basis analysis. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is considered acceptable due to the low probability of an event occurring that would require the remaining vacuum breaker capability.

B.1 An open vacuum breaker allows communication between the drywell and suppression chamber airspace, and, as a result, there is the potential for primary containment overpressurization due to bypass leakage if a LOCA were to occur. Therefore, the open vacuum breaker must be closed.

A short time is allowed to close the vacuum breaker due to the low probability of an event that would pressurize primary containment. If vacuum breaker position indication is not reliable, an alternate method of verifying that the vacuum breakers are closed is to verify the bypass leakage between the drywell and suppression chamber is within the limits of SR 3.6.1.1.2 or by local observation. The required 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is considered adequate to perform this test. If the leak test fails, not only must this ACTION be taken (close the open vacuum breaker within the required Completion Time), but also the appropriate Conditions and Required Actions of LCO 3.6.1.1, "Primary Containment," must be entered.

C.1 and C.2 If any Required Action and associated Completion Time cannot be met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours0.5 days 0.0714 weeks 0.0164 months and to MODE 4 within 36 hours1.5 days 0.214 weeks 0.0493 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.1.7.1 REQUIREMENTS Each vacuum breaker is verified closed to ensure that this potential large bypass leakage path is not present. This Surveillance is performed by observing local or relay room vacuum breaker position indication or by performing (continued)

JAFNPP B 3.6.1.7-4 Revision 0

Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.T BASES SURVEILLANCE SR 3.6.1.7.1 (continued)

REQUIREMENTS SR 3.6.1.1.2, the bypass leakage test. If the bypass test fails, not only must the vacuum breaker(s) be considered open and the appropriate Conditions and Required Actions of this LCO be entered, but also the appropriate Condition and Required Actions of LCO 3.6.1.1 must be entered. Each suppression chamber-to-drywell vacuum breaker disc will be seated as long as the arm movement is

1.0 degree. The vacuum breakers are considered closed if the associated position light indicates the closed position since it is set to actuate at

1.0 degree. The 14 day Frequency is based on engineering judgment, is considered adequate in view of other indications of vacuum breaker status available to operations personnel, and has been shown to be acceptable through operating experience.

Two Notes are added to this SR. The first Note allows suppression chamber-to-drywell vacuum breakers opened in conjunction with the performance of a Surveillance to not be considered as failing this SR. These periods of opening vacuum breakers are controlled by plant procedures and do not represent inoperable vacuum breakers.

The second Note is included to clarify that vacuum breakers open due to an actual differential pressure are not considered as failing this SR.

SR 3.6.1.7.2 Each vacuum breaker must be cycled to ensure that it opens adequately to perform its design function and returns to the fully closed position. This ensures that the safety analysis assumptions are valid. The Frequency of this SR is in accordance with the Inservice Testing Program.

SR 3.6.1.7.3 Verification of the vacuum breaker opening setpoint is necessary to ensure that the safety analysis assumption regarding vacuum breaker opening differential pressure of 0.5 psid is valid. The 24 month Frequency has been shown to be acceptable, based on operating experience, and is further justified because SR 3.6.1.7.2 is performed at a shorter Frequency that conveys the proper functioning status of each vacuum breaker.

(continued)

JAFNPP B 3.6.1.7-5 Revision 0

Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.7 BASES (continued)

REFERENCES 1. UFSAR, Section 14.6.1.3.3.

2. UFSAR, Section 5.2.3.6.

3. UFSAR, Section 5.2.4.2.

4. Preliminary Hazards Summary Report, Bodega Bay Atomic Park Unit Number 1, Docket No. 50-205, Appendix I, December 28, 1962.

JAFNPP B 3.6.1.7-6 Revision 0

MSLC System B 3.6.1.8 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.8 Main Steam Leakage Collection (MSLC) System BASES BACKGROUND The MSLC System supplements the isolation function of the MSIVs by processing the fission products that could leak through the closed MSIVs after a Design Basis Accident (DBA) loss of coolant accident (LOCA).

The MSLC System consists of two independent and redundant subsystems. Each subsystem collects leakage from the stem packing of all four outboard main steam isolation valves (MSIVs) and downstream of all outboard MSIVs. Each subsystem consists of valves, controls and piping which can be aligned to the Standby Gas Treatment (SGT) System for processing. During operation, the SGT System maintains sufficient negative pressure to provide the MSLC System flow required to ensure that all postulated leakage is collected and processed (Ref. 1). While both the stem packing and the downstream portion of each subsystem contribute to reducing uncontrolled or untreated MSIV leakage, the downstream portion performs the primary function of the MSLC System to collect and process the leakage across the MSIV seats. The downstream portion is provided with interlocks that prevent inadvertent operation of the system during normal operation and to prevent improper system lineup during accident conditions.

Each downstream portion of the MSLC subsystems includes a remote manual isolation valve, an automatic isolation valve, and a backup automatic isolation valve. A pressure switch which monitors MSLC System piping pressure is provided for each automatic isolation valve. These pressure switches act to prevent the opening of the valves and to automatically close the valves on high pressure. The pressure switches will indicate low pressure during normal plant operation since the remote manual isolation valves will isolate the pressure switches from main steam pressure. The operator initiates the operation of the stem packing portion of the MSLC subsystem by opening the associated remote manual isolation valve. The operator initiates operation of the downstream portion of each MSLC subsystem by first opening the associated remote manual isolation valve. The operator then places the control switch associated with the automatic isolation valves to open. If the MSLC System pressure is greater than 16 psig the valves will remain shut and automatically open at or below 16 psig.

(continued)

JAFNPP B 3.6.1.8-1 Revision 0

MSLC System B 3.6.1.8 BASES BACKGROUND The MSLC System is manually initiated approximately (continued) 20 minutes following a DBA LOCA (Ref. 2).

APPLICABLE The MSLC System mitigates the consequences of a DBA LOCA by SAFETY ANALYSES ensuring that fission products that may leak from the closed MSIVs are diverted to and filtered by the SGT System. The operation of the MSLC System prevents a release of untreated leakage for this type of event.

The MSLC System satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii) (Ref. 3).

LCO One MSLC subsystem can provide the required processing of the MSIV leakage. To ensure that this capability is available, assuming worst case single failure, two MSLC subsystems must be OPERABLE.

APPLICABILITY In MODES 1, 2, and 3, a DBA could lead to a fission product release to primary containment. Therefore, MSLC System OPERABILITY is required during these MODES. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining the MSLC System OPERABLE is not required in MODE 4 or 5 to ensure MSIV leakage is processed.

ACTIONS A.1 With one MSLC subsystem inoperable, the inoperable MSLC subsystem must be restored to OPERABLE status within 30 days. In this Condition, the remaining OPERABLE MSLC subsystem is adequate to perform the required leakage control function. However, the overall reliability is reduced because a single failure in the remaining subsystem could result in a total loss of MSIV leakage control function. The 30 day Completion Time is based on the redundant capability afforded by the remaining OPERABLE MSLC subsystem and the low probability of a DBA LOCA occurring during this period.

(continued)

JAFNPP B 3.6.1.8-2 Revision 0

MSLC System B 3.6.1.8 BASES ACTIONS nued) B.1 (conti With two MSLC subsystems inoperable, at least one subsystem must be restored to OPERABLE status within 7 days. The 7 day Completion Time is based on the low probability of the occurrence of a DBA LOCA.

C.1 and C.2 If the MSLC subsystem cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours0.5 days 0.0714 weeks 0.0164 months and to MODE 4 within 36 hours1.5 days 0.214 weeks 0.0493 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.1.8.1 REQUIREMENTS Verifying the correct alignment for manual, power operated, and automatic valves in the MSLC System flow path provides assurance that the proper flow path exists for system operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve is also allowed to be in the nonaccident position provided it can be aligned to the accident position within the time assumed in the accident analysis. This is acceptable since the MSLC System is manually initiated. This SR does not require any testing or valve manipulation: rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.

The Frequency of 31 days is justified because the valves are operated under procedural control, improper valve position would affect only a single subsystem, the probability of an event requiring initiation of the system is low, and the subsystem is a manually initiated system. This Frequency has been shown to be acceptable based on operating experience.

(continued)

JAFNPP B 3.6.1.8-3 Revision 0

MSLC System B 3.6.1.8_

BASES SURVEILLANCE SR 3.6.1.8.2 REQUIREMENTS (continued) A system functional test is performed to ensure that the MSLC System will operate through its operating sequence.

This includes verifying that the automatic positioning of the valves and the operation of each interlock are correct.

While this Surveillance can be performed with the reactor at power, operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

REFERENCES 1. UFSAR, Section 9.19.

2. Regulatory Guide 1.96, Revision 1, Design Of Main Steam Isolation Valve Leakage Control Systems For Boiling Water Reactor Nuclear Power Plants, June 1976.

JAFNPP B 3.6.1.8-4 Revision 0

RHR Containment Spray System B 3.6.1.9 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.9 Residual Heat Removal (RHR) Containment Spray System BASES BACKGROUND The primary containment is designed with a suppression pool so that, in the event of a loss of coolant accident (LOCA),

steam released from the primary system is channeled through the suppression pool water and condensed without producing significant pressurization of the primary containment. The primary containment is designed so that with the pool initially at the minimum water volume and the worst single active failure of the primary containment heat removal systems, suppression pool energy absorption combined with subsequent operator controlled pool cooling will prevent the primary containment pressure from exceeding its design value. However, the primary containment must also withstand a postulated bypass leakage pathway that allows the passage of steam from the drywell directly into the suppression chamber airspace, bypassing the suppression pool. The RHR Containment Spray System is designed to mitigate the effects of bypass leakage and to prevent the drywell temperature from exceeding its design value of 309°F (Ref. 1) for a significant period of time and to ensure the safety equipment can perform its associated function during a design basis event.

There are two redundant, 100% capacity RHR containment spray subsystems. Each subsystem consists of a suction line from the suppression pool, two RHR pumps, a heat exchanger, and its associated spray header embedded in and protected by the primary shield wall located in the drywell and to a common spray header suspended in the suppression chamber above the minimum water level.

The RHR containment spray mode may be manually initiated, if required, following a LOCA, according to emergency procedures.

APPLICABLE Reference 2 contains the results of analyses that predict SAFETY ANALYSES the primary containment pressure response for a LOCA with the maximum allowable bypass leakage area.

The maximum allowable equivalent flow path area for bypass leakage has been specified to be 0.032 ft 2 . The analysis demonstrates that with containment spray operation the primary containment pressure remains within design limits.

(continued)

JAFNPP B 3.6.1.9-1 Revision 0

RHR Containment Spray System B 3.6.1.9 BASES APPLICABLE Steam line breaks have been analyzed to develop a drywell SAFETY ANALYSES air temperature history for use in equipment qualification (continued) (Refs. 3 and 4). The RHR containment sprays are assumed to be initiated at a minimum time of 10 minutes. The RHR containment spray flow rates were assumed to be 7,150 gpm for drywell sprays and 600 gpm for suppression chamber sprays. The highest air temperature envelope is 335°F for 2 the first 300 seconds and this is as a result of a 0.75 ft steam line break (Ref. 4). The analysis (Ref. 4) concluded containment design temperature is not exceeded since drywell spray activiation will terminate any further rise in drywell air temperature.

The RHR Containment Spray System satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii) (Ref. 5).

LCO In the event of a Design Basis Accident (DBA), a minimum of one RHR containment spray subsystem is required to mitigate potential bypass leakage paths and maintain the primary containment peak pressure and temperature below design limits. To ensure that these requirements are met, two RHR containment spray subsystems must be OPERABLE. Therefore, in the event of an accident, at least one subsystem is OPERABLE assuming the worst case single active failure. An RHR containment spray subsystem is OPERABLE when one of the pumps, the heat exchanger, and associated piping, valves, instrumentation, and controls are OPERABLE.

APPLICABILITY In MODES 1, 2, and 3, a DBA could cause pressurization and heating of primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES.

Therefore, maintaining RHR containment spray subsystems OPERABLE is not required in MODE 4 or 5.

ACTIONS A.1 With one RHR containment spray subsystem inoperable, the inoperable subsystem must be restored to OPERABLE status within 7 days. In this Condition, the remaining OPERABLE RHR containment spray subsystem is adequate to perform the primary containment cooling function. However, the overall reliability is reduced because a single active failure in the OPERABLE subsystem could result in reduced primary (continued)

JAFNPP B 3.6.1.9-2 Revision 0

RHR Containment Spray System B 3.6.1.9 BASES ACTIONS A.1 (continued) containment cooling capability. The 7 day Completion Time was chosen in light of the redundant RHR containment capabilities afforded by the OPERABLE subsystem and the low probability of a DBA occurring during this period.

B.1 With two RHR containment spray subsystems inoperable, one subsystem must be restored to OPERABLE status within 8 hours0.333 days 0.0476 weeks 0.011 months . In this Condition, there is a substantial loss of the primary containment bypass leakage and temperature mitigation function. The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is based on this loss of function and is considered acceptable due to the low probability of a DBA and because alternative methods to remove heat from primary containment are available.

C.1 and C.2 If any Required Action and associated Completion Time is not met the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours0.5 days 0.0714 weeks 0.0164 months and to MODE 4 within 36 hours1.5 days 0.214 weeks 0.0493 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.1.9.1 REQUIREMENTS Verifying the correct alignment for manual, power operated, and automatic valves in the RHR containment spray mode flow path provides assurance that the proper flow paths will exist for system operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these were verified to be in the correct position prior to locking, sealing, or securing. A valve is also allowed to be in the nonaccident position provided it can be aligned to the accident position within the time assumed in the accident analysis. This is acceptable since the RHR Containment Spray System is manually initiated.

This SR does not require any testing or valve manipulation; (continued)

JAFNPP B 3.6.1.9-3 Revision 0

RHR Containment Spray System B 3.6.1.9 BASES SURVEILLANCE SR 3.6.1.9.1 (continued)

REQUIREMENTS rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.

The 31 day Frequency of this SR is justified because the valves are operated under procedural control and because improper valve position would affect only a single subsystem. This Frequency has been shown to be acceptable based on operating experience.

SR 3.6.1.9.2 Verifying each required RHR pump develops a flow rate

ý 7750 gpm while operating in the suppression pool cooling mode with flow through the associated heat exchanger ensures that pump performance has not degraded during the cycle. It is tested in the pool cooling mode to demonstrate pump OPERABILITY without spraying down equipment in the drywell.

Flow is a normal test of centrifugal pump performance required by the ASME Code,Section XI (Ref. 6). This test confirms one point on the pump performance curve and is indicative of overall performance. Such inservice tests confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance. The Frequency of this SR is in accordance with the Inservice Testing Program.

SR 3.6.1.9.3 This Surveillance is performed every 10 years by introduction of air to verify that the spray nozzles are not obstructed and that flow will be provided when required.

The 10 year Frequency is adequate to detect degradation in performance due to the passive nozzle design and its normally dry state and has been shown to be acceptable through operating experience.

REFERENCES 1. UFSAR, Table 5.2-1.

2. UFSAR, Section 5.2.4.4.

3. UFSAR, Section 14.6.

(continued)

JAFNPP B 3.6.1.9-4 Revision 0

RHR Containment Spray System B 3.6.1.9.

BASES REFERENCES 4. GE-NE-T23-00737-01, James A. FitzPatrick Nuclear Power (continued) Plant Higher RHR Service Water Temperature Analysis, August 1996.

6. ASME, Boiler and Pressure Vessel Code,Section XI.

JAFNPP B 3.6.1.9-5 Revision 0

Suppression Pool Average Temperature B 3.6.2.1 B 3.6 CONTAINMENT SYSTEMS B 3.6.2.1 Suppression Pool Average Temperature BASES BACKGROUND The suppression chamber is a toroidal shaped, steel pressure vessel containing a volume of water called the suppression pool. The suppression pool is designed to absorb the decay heat and sensible energy released during a reactor blowdown from safety/relief valve discharges or from Design Basis Accidents (DBAs). The suppression pool must quench all the steam released through the downcomer lines during a loss of coolant accident (LOCA). This is the essential mitigative feature of a pressure suppression containment that ensures that the peak containment pressure is maintained below the maximum allowable pressure for DBAs (62 psig). The suppression pool must also condense steam from steam exhaust lines in the turbine driven systems (i.e., the High Pressure Coolant Injection System and Reactor Core Isolation Cooling System). Suppression pool average temperature (along with LCO 3.6.2.2, "Suppression Pool Water Level") is a key indication of the capacity of the suppression pool to fulfill these requirements.

The technical concerns that lead to the development of suppression pool average temperature limits are as follows:

a. Complete steam condensation;

b. Primary containment peak pressure and temperature;

c. Condensation oscillation loads; and

d. Chugging loads.

APPLICABLE The postulated DBA against which the primary containment SAFETY ANALYSES performance is evaluated is the entire spectrum of postulated pipe breaks within the primary containment.

Inputs to the safety analyses include initial suppression pool temperature. (Reference 1 for LOCAs and References 2 and 3 for the pool temperature analyses required by Reference 4). An initial pool temperature of 95 0 F is assumed for the References 1. 2, and 3 analyses. Reactor shutdown at a pool temperature of 1107F and vessel depressurization at a pool temperature of 120'F were cases addressed as part of the pool temperature analyses of Reference 2. The limiting case of rapid depressurization (continued)

JAFNPP B 3.6.2.1-1 Revision 0

Suppression Pool Average Temperature B 3.6.2.L BASES APPLICABLE from isolated Hot Shutdown (reactor scram and main steam SAFETY ANALYSES isolation valve closure, with initial pool temperature of (continued) 95 0 F) with assumed loss of one residual heat removal loop (Reference 2) was addressed as part of the analyses of Reference 3. The limit of 105'F, at which testing is terminated, is not used in the safety analyses because DBAs are assumed to not initiate during plant testing.

Suppression pool average temperature satisfies Criteria 2 and 3 of 10 CFR 50.36(c)(2)(ii) (Ref. 5).

LCO A limitation on the suppression pool average temperature is required to provide assurance that the containment conditions assumed for the safety analyses are met. This limitation ensures that peak primary containment pressures and temperatures do not exceed maximum allowable values during a postulated DBA or any transient resulting in heatup of the suppression pool. The LCO requirements are:

a. Average temperature

95 0 F with THERMAL POWER > 1%RTP and no testing that adds heat to the suppression pool is being performed. This requirement ensures that licensing bases initial conditions are met.

b. Average temperature

105 0 F with THERMAL POWER

> 1% RTP and testing that adds heat to the suppression pool is being performed. This required value ensures that the plant has testing flexibility, and was selected to provide margin below the 110OF limit at which reactor shutdown is required. When testing ends, temperature must be restored to g 95 0 F within 24 hours1 days 0.143 weeks 0.0329 months according to Required Action A.2. Therefore, the time period that the temperature is > 95 0 F is short enough not to cause a significant increase in plant risk.

c. Average temperature g 110°F with THERMAL POWER

1% RTP. This requirement ensures that the plant will be shut down at > 110 0 F. The pool is designed to absorb decay heat and sensible heat but could be heated beyond design limits by the steam generated if the reactor is not shut down.

Indication of 1%RTP varies with plant conditions and can be determined by more than one method. When at or near normal operating temperature, Reactor Coolant System (RCS) losses such as the Reactor Water Cleanup System, steam line drains and insulation inefficiency are approximately 1%RTP or (continued)

JAFNPP B 3.6.2.1-2 Revision 0

Suppression Pool Average Temperature B 3.6.2.1I BASES LCO less and reactor power level can be observed on the (continued) intermediate range monitor (IRM) Instrumentation. At this condition 25/40 divisions of full scale on IRM Range 7 is a convenient measure of reactor power essentially equivalent to 1%RTP. At 1%RTP, heat input is approximately equal to normal system heat losses. When RCS temperature is significantly below the normal operating temperature, maintaining reactor power level at or below the "point of adding heat" maintains power level well below 1%RTP.

APPLICABILITY In MODES 1, 2, and 3, a DBA could cause significant heatup of the suppression pool. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES.

Therefore, maintaining suppression pool average temperature within limits is not required in MODE 4 or 5.

ACTIONS A.1 and A.2 With the suppression pool average temperature above the specified limit when not performing testing that adds heat to the suppression pool and when above the specified power indication, the initial conditions exceed the conditions assumed for the References 1, 2, and 3 analyses. However, primary containment cooling capability still exists, and the primary containment pressure suppression function will occur at temperatures well above those assumed for safety analyses. Therefore, continued operation is allowed for a limited time. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is adequate to allow the suppression pool average temperature to be restored below the limit. Additionally, when suppression pool temperature is > 95°F, increased monitoring of the suppression pool temperature is required to ensure that it remains : 110'F. The once per hour Completion Time is adequate based on past experience, which has shown that pool temperature increases relatively slowly except when testing that adds heat to the suppression pool is being performed.

Furthermore, the once per hour Completion Time is considered adequate in view of other indications in the control room, including alarms, to alert the operator to an abnormal suppression pool average temperature condition.

B.1 If the suppression pool average temperature cannot be restored to within limits within the required Completion Time, the plant must be brought to a MODE in which the LCO (continued)

JAFNPP B 3.6.2.1-3 Revision 0

Suppression Pool Average Temperature B 3.6.2.1 BASES ACTIONS B.1 (continued) does not apply. To achieve this status, THERMAL POWER must be reduced to : 1% RTP within 12 hours0.5 days 0.0714 weeks 0.0164 months . The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time is reasonable, based on operating experience, to reduce power from full power conditions in an orderly manner and without challenging plant systems.

C.1 Suppression pool average temperature is allowed to be > 95°F when THERMAL POWER > 1%RTP, and during testing that adds heat to the suppression pool. However, if the temperature is > 105 0 F, all testing must be immediately suspended to preserve the heat absorption capability of the suppression pool. With the testing suspended, Condition A is entered and the Required Actions and associated Completion Times are applicable.

D.1, D.2, and D.3 Suppression pool average temperature > 110°F requires that the reactor be shut down immediately. This is accomplished by placing the reactor mode switch in the shutdown position.

Further cooldown to Mode 4 within 36 hours1.5 days 0.214 weeks 0.0493 months is required at normal cooldown rates (provided pool temperature remains 0

< 120 F). Additionally, when suppression pool temperature is > 110 0 F, increased monitoring of pool temperature is required to ensure that it remains

120 0 F. The once per 30 minute Completion Time is adequate, based on operating experience. Given the high suppression pool average temperature in this Condition the monitoring Frequency is increased to twice that of Condition A. Furthermore, the 30 minute Completion Time is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal suppression pool average temperature condition.

E.1 and E.2 If suppression pool average temperature cannot be maintained at : 120 0 F, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the reactor pressure must be reduced to < 200 psig within 12 hours0.5 days 0.0714 weeks 0.0164 months , and (continued)

JAFNPP B 3.6.2.1-4 Revision 0

Suppression Pool Average Temperature B 3.6.2.1_

BASES ACTIONS E.1 and E.2 (continued) the plant must be brought to at least MODE 4 within 36 hours1.5 days 0.214 weeks 0.0493 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

Continued addition of heat to the suppression pool with suppression pool temperature > 120°F could result in exceeding the design basis maximum allowable values for primary containment temperature or pressure. Furthermore, if a blowdown were to occur when the temperature was

> 120 0 F, the maximum allowable bulk and local temperatures could be exceeded very quickly.

SURVEILLANCE SR 3.6.2.1.1 REQUIREMENTS The suppression pool average temperature is regularly monitored to ensure that the required limits are satisfied.

The LCO 3.3.3.1, "Post Accident Monitoring (PAM)

Instrumentation," Bases contains a description of the suppression pool temperature monitoring system. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency has been shown, based on operating experience, to be acceptable. When heat is being added to the suppression pool by testing, however, it is necessary to monitor suppression pool temperature more frequently. The 5 minute Frequency during testing is justified by the rates at which tests will heat up the suppression pool, has been shown to be acceptable based on operating experience, and provides assurance that allowable pool temperatures are not exceeded.

The Frequencies are further justified in view of other indications available in the control room, including alarms, to alert the operator to an abnormal suppression pool average temperature condition.

REFERENCES 1. UFSAR, Section 14.6.1.3.3.

2. NEDC-24361-P, James A. FitzPatrick Nuclear Power Plant Suppression Pool Temperature Response, August 1981.

3. GE-NE-T23-00737-01, James A. FitzPatrick Nuclear Power Plant Higher RHR Service Water Temperature Analysis, August 1996.

(continued)

JAFNPP B 3.6.2.1-5 Revision 0

Suppression Pool Average Temperature B 3.6.2.1_

BASES REFERENCES 4. Letter from R. W. Reid (NRC) to G. T. Berry (NYPA),

(continued) Request for Additional Information Regarding Suppression Pool Temperature Transients, December 9, 1977.

JAFNPP B 3.6.2.1-6 Revision 0

Suppression Pool Water Level B 3.6.2.2_

B 3.6 CONTAINMENT SYSTEMS B 3.6.2.2 Suppression Pool Water Level BASES BACKGROUND The suppression chamber is a toroidal shaped, steel pressure vessel containing a volume of water called the suppression pool. The suppression pool is designed to absorb the energy associated with decay heat and sensible heat released during a reactor blowdown from safety/relief valve (S/RV) discharges or from a Design Basis Accident (DBA). The suppression pool must quench all the steam released through the Mark I Vent System downcomer lines during a loss of coolant accident (LOCA). This is the essential mitigative feature of a pressure suppression containment, which ensures that the peak containment pressure is maintained below the maximum allowable pressure for DBAs (62 psig). The suppression pool must also condense steam from the steam exhaust lines in the turbine driven systems (i.e., High Pressure Coolant Injection (HPCI) System and Reactor Core Isolation Cooling (RCIC) System) and provides the main emergency water supply source for the reactor vessel. The suppression pool volume ranges between approximately 105,900 ft 3 at the low water level limit of 13.88 ft and 107,400 ft 3 at the high water level limit of 14 ft.

If the suppression pool water level is too low, an insufficient amount of water would be available to adequately condense the steam from the S/RV quenchers, drywell vents, or HPCI and RCIC turbine exhaust lines. Low suppression pool water level could also result in an inadequate emergency makeup water source to the Emergency Core Cooling System. The lower volume would also absorb less steam energy before heating up excessively. Therefore, a minimum suppression pool water level is specified.

If the suppression pool water level is too high, it could result in excessive clearing loads from S/RV discharges and excessive pool swell loads during a DBA LOCA. Therefore, a maximum pool water level is specified. This LCO specifies an acceptable range to prevent the suppression pool water level from being either too high or too low.

APPLICABLE Initial suppression pool water level affects suppression SAFETY ANALYSES pool temperature response calculations, calculated drywell pressure during vent system downcomer clearing for a DBA, calculated pool swell loads for a DBA LOCA, and calculated (continued)

JAFNPP B 3.6.2.2-1 Revision 0

Suppression Pool Water Level B 3.6.2.2-BASES APPLICABLE loads due to S/RV discharges. Suppression pool water level SAFETY ANALYSES must be maintained within the limits specified so that the (continued) safety analysis of References 1 and 2 remain valid.

Suppression pool water level satisfies Criteria 2 and 3 of 10 CFR 50.36(c)(2)(ii) (Ref. 3).

LCO A limit that suppression pool water level be 2 13.88 ft and

14 ft is required to ensure that the primary containment conditions assumed for the safety analyses are met. Either the high or low water level limits were used in the safety analyses, depending upon which is more conservative for a particular calculation.

The LCO is modified by a note which states that the LCO is not required to be met up to four hours during Surveillances that cause suppression pool water level to be outside of limits. These Surveillances include required OPERABILITY testing of the High Pressure Coolant Injection System, the Reactor Core Isolation Cooling System, the suppression chamber-to-drywell vacuum breakers, the Core Spray System and the Residual Heat Removal System. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months allowance is adequate to perform the Surveillances and to restore the suppression pool water level to within limits.

APPLICABILITY In MODES 1, 2, and 3, a DBA would cause significant loads on the primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. The requirement for maintaining suppression pool water level within limits in MODE 4 or 5 is addressed in LCO 3.5.2.

"ECCS - Shutdown."

ACTIONS A.1 With suppression pool water level outside the limits, the conditions assumed for the safety analyses are not met. If water level is below the minimum level, the pressure suppression function still exists as long as the vent system downcomer lines are covered, HPCI and RCIC turbine exhausts are covered, and S/RV quenchers are covered. If suppression pool water level is above the maximum level, protection against overpressurization still exists due to the margin in the peak containment pressure analysis and the capability of the Residual Heat Removal Containment Spray System.

(continued)

JAFNPP B 3.6.2.2-2 Revision 0

Suppression Pool Water Level B 3.6.2.2-BASES ACTIONS A.1 (continued)

Therefore, continued operation for a limited time is allowed. The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is sufficient to restore suppression pool water level to within limits.

Also, it takes into account the low probability of an event requiring the suppression pool water level to be within limits occurring during this interval.

B.1 and B.2 If suppression pool water level cannot be restored to within limits within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours0.5 days 0.0714 weeks 0.0164 months and to MODE 4 within 36 hours1.5 days 0.214 weeks 0.0493 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.2.2.1 REQUIREMENTS Verification of the suppression pool water level is to ensure that the required limits are satisfied. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency has been shown to be acceptable based on operating experience. Furthermore, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal suppression pool water level condition.

REFERENCES 1. UFSAR, Section 14.6.1.3.3.

2-. GE-NE-T23-00737-01, James A. FitzPatrick Nuclear Power Plant Higher RHR Service Water Temperature Analysis, August 1996.

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RHR Suppression Pool Cooling B 3.6.2.3_

B 3.6 CONTAINMENT SYSTEMS B 3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling BASES BACKGROUND Following a Design Basis Accident (DBA), the RHR Suppression Pool Cooling System removes heat from the suppression pool.

The suppression pool is designed to absorb the sudden input of heat from the primary system. In the long term, the pool continues to absorb residual heat generated by fuel in the reactor core. Some means must be provided to remove heat from the suppression pool so that the temperature inside the primary containment remains within design limits. This function is provided by two redundant RHR suppression pool cooling subsystems. The purpose of this LCO is to ensure that both subsystems are OPERABLE in applicable MODES.

Each RHR suppression pool cooling subsystem (loop) contains two pumps and one heat exchanger and is manually initiated and independently controlled. The two subsystems perform the suppression pool cooling function by circulating water from the suppression pool through the RHR heat exchangers and returning it to the suppression pool. RHR service water, circulating through the tube side of the heat exchangers, exchanges heat with the suppression pool water and discharges this heat to the ultimate heat sink.

The heat removal capability of one RHR pump is sufficient to meet the overall DBA pool cooling requirement for loss of coolant accidents (LOCAs) and transient events such as a turbine trip or stuck open safety/relief valve (S/RV). S/RV leakage, High Pressure Coolant Injection System and Reactor Core Isolation Cooling System testing increase suppression pool temperature more slowly. The RHR Suppression Pool Cooling System is also used to lower the suppression pool water bulk temperature following such events. The RHR Suppression Pool Cooling System also ensures adequate net positive suction head (NPSH) is available for the Emergency Core Cooling System pumps.

APPLICABLE References 1 and 2 contain the results of analyses used to SAFETY ANALYSES predict primary containment pressure and temperature following large and small break LOCAs. References 2 and 3 contain the results of analyses used to predict local and bulk suppression pool temperatures following certain events including small break LOCAs and a stuck open S/RV. The analyses indicates that the heat removal capacity of the RHR (continued)

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RHR Suppression Pool Cooling B 3.6.2.3-BASES APPLICABLE Suppression Pool Cooling System is adequate to maintain the SAFETY ANALYSES primary containment conditions within design limits. The (continued) suppression pool temperature is calculated to remain below the design limit.

The RHR Suppression Pool Cooling System satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii) (Ref. 4).

LCO Following a DBA, a minimum of one RHR suppression pool cooling subsystem is required to maintain the primary containment peak pressure and temperature below design limits (Ref. 3). To ensure that these requirements are met, two RHR suppression pool cooling subsystems must be OPERABLE with power from two safety related redundant power supplies.

Therefore, in the event of an accident, at least one subsystem is OPERABLE assuming the worst case single active component failure. An RHR suppression pool cooling subsystem is OPERABLE when one of the pumps, the heat exchanger, and associated piping, valves, instrumentation, and controls are OPERABLE.

APPLICABILITY In MODES 1, 2, and 3. a DBA could cause a release of radioactive material to primary containment and cause a heatup and pressurization of primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, the RHR Suppression Pool Cooling System is not required to be OPERABLE in MODE 4 or 5.

ACTIONS A.1 With one RHR suppression pool cooling subsystem inoperable, the inoperable subsystem must be restored to OPERABLE status within 7 days. In this Condition, the remaining RHR suppression pool cooling subsystem is adequate to perform the primary containment cooling function. However, the overall reliability is reduced because a single active component failure in the OPERABLE subsystem could result in reduced primary containment cooling capability. The 7 day Completion Time is acceptable in light of the redundant RHR suppression pool cooling capabilities afforded by the OPERABLE subsystem and the low probability of a DBA occurring during this period.

(continued)

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RHR Suppression Pool Cooling B 3.6.2.3 BASES ACTIONS B.1 (continued)

With two RHR suppression pool cooling subsystems inoperable, one subsystem must be restored to OPERABLE status within 8 hours0.333 days 0.0476 weeks 0.011 months . In this condition, there is a substantial loss of the primary containment pressure and temperature mitigation function. The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is based on this loss of function and is considered acceptable due to the low probability of a DBA and the potential avoidance of a plant shutdown transient that could result in the need for the RHR suppression pool cooling subsystems to operate.

C.1 and C.2 If any Required Action and associated Completion Time cannot be met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours0.5 days 0.0714 weeks 0.0164 months and to MODE 4 within 36 hours1.5 days 0.214 weeks 0.0493 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.2.3.1 REQUIREMENTS Verifying the correct alignment for manual, power operated, and automatic valves in the RHR suppression pool cooling mode flow path provides assurance that the proper flow path exists for system operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve is also allowed to be in the nonaccident position provided it can be aligned to the accident position within the time assumed in the accident analysis. This is acceptable since the RHR suppression pool cooling mode is manually initiated. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.

The Frequency of 31 days is justified because the valves are operated under procedural control, improper valve position would affect only a single subsystem, the probability of an (continued)

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RHR Suppression Pool Cooling B 3.6.2.3.

BASES SURVEILLANCE SR 3.6.2.3.1 (continued)

REQUIREMENTS event requiring initiation of the system is low, and the system is a manually initiated system. This Frequency has been shown to be acceptable based on operating experience.

SR 3.6.2.3.2 Verifying that each required RHR pump develops a flow rate

7700 gpm while operating in the suppression pool cooling mode with flow through the associated heat exchanger ensures that pump performance has not degraded during the cycle.

Flow is a normal test of centrifugal pump performance required by ASME Code,Section XI (Ref. 5). This test confirms one point on the pump performance curve, and the results are indicative of overall performance. Such inservice tests confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance. The Frequency of this SR is in accordance with the Inservice Testing Program.

REFERENCES 1. UFSAR, Section 14.6.1.3.3.

2. GE-NE-T23-00737-01, James A. FitzPatrick Nuclear Power Plant Higher RHR Service Water Temperature Analysis, August 1996.

3. NEDC-24361-P, James. A FitzPatrick Nuclear Power Plant Suppression Pool Temperature Response, August 1981.

5. ASME, Boiler and Pressure Vessel Code,Section XI.

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Drywell-to-Suppression Chamber Differential Pressure B 3.6.2.4 B 3.6 CONTAINMENT SYSTEMS B 3.6.2.4 Drywell-to-Suppression Chamber Differential Pressure BASES BACKGROUND The toroidal shaped suppression chamber, which contains the suppression pool, is connected to the drywell (part of the primary containment) by eight drywell vent pipes. The drywell vent pipes exhaust into a continuous vent header, from which 96 downcomer pipes extend into the suppression pool. The downcomer pipe exits are approximately 4 ft below the minimum suppression pool water level required by LCO 3.6.2.2, "Suppression Pool Water Level." During a loss of coolant accident (LOCA), the increasing drywell pressure will force the waterleg in the downcomer pipes into the suppression pool at substantial velocities as the "blowdown" phase of the event begins. The length of the waterleg has a significant effect on the resultant primary containment pressures and loads.

APPLICABLE The purpose of maintaining the drywell at a slightly higher SAFETY ANALYSES pressure with respect to the suppression chamber is to minimize the drywell pressure increase necessary to clear the downcomer pipes to commence condensation of steam in the suppression pool and to minimize the mass of the accelerated downcomer waterleg. This reduces the hydrodynamic loads on the torus during the LOCA blowdown (Ref. 1). The required differential pressure results in a downcomer waterleg of 0.37 ft to 0.49 ft.

Initial drywell-to-suppression chamber differential pressure affects both the dynamic pool loads on the suppression chamber and the peak drywell pressure during downcomer pipe clearing during a Design Basis LOCA. Drywell-to-suppression chamber differential pressure must be maintained within the specified limits so that the safety analysis remains valid.

Drywell-to-suppression chamber differential pressure satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii) (Ref. 2).

LCO A drywell-to-suppression chamber differential pressure limit of 1.7 psi is required to ensure that the containment conditions assumed in the safety analyses are met. A drywell-to-suppression chamber differential pressure of 1.7 psi corresponds to a downcomer water leg of 0.37 ft to 0.49 ft if suppression pool level is within the limits specified in LCO 3.6.2.2. Failure to maintain the required (continued)

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Drywell-to-Suppression Chamber Differential Pressure B 3.6.2.4_

BASES LCO differential pressure could result in excessive forces on (continued) the suppression chamber due to higher water clearing loads from downcomer pipes and higher pressure buildup in the drywell.

The LCO is modified by a Note which states that the LCO is not required to be met up to four hours during Surveillances that cause or require drywell-to-suppression chamber differential pressure to be outside of limits. These Surveillances include required OPERABILITY testing of the High Pressure Coolant Injection System, the Reactor Core Isolation Cooling System, and the suppression chamber-to drywell vacuum breakers. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months allowance is adequate to perform the Surveillances and to restore the drywell-to suppression chamber differential pressure to within limits.

APPLICABILITY Drywell-to-suppression chamber differential pressure must be controlled when the primary containment is inert. The primary containment must be inert in MODE 1, since this is the condition with the highest probability for an event that could produce hydrogen. It is also the condition with the highest probability of an event that could impose large loads on the primary containment.

Inerting primary containment is an operational problem because it prevents primary containment access without an appropriate breathing apparatus. Therefore, the primary containment is inerted as late as possible in the plant startup and is de-inerted as soon as possible in the plant shutdown. As long as reactor power is < 15% RTP, the probability of an event that generates hydrogen or excessive loads on primary containment occurring within the first 24 hours1 days 0.143 weeks 0.0329 months following a startup or within the last 24 hours1 days 0.143 weeks 0.0329 months prior to a shutdown is low enough that these "windows," with the primary containment not inerted, are also justified.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months time period is a reasonable amount time to allow plant personnel to perform inerting or de-inerting.

ACTIONS A.1 If drywell-to-suppression chamber differential pressure is not within the limit, the conditions assumed in the safety analyses are not met and the differential pressure must be restored to within the limit within 8 hours0.333 days 0.0476 weeks 0.011 months . The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time provides sufficient time to restore (continued)

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Drywell-to-Suppression Chamber Differential Pressure B 3.6.2.4 BASES ACTIONS A.1 (continued) differential pressure to within limit and takes into account the low probability of an event that would create excessive suppression chamber loads occurring during this time period.

B.1 If the differential pressure cannot be restored to within limits within the associated Completion Time, the plant must be placed in a MODE in which the LCO does not apply. This is done by reducing power to : 15% RTP within 12 hours0.5 days 0.0714 weeks 0.0164 months . The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time is reasonable, based on operating experience, to reduce reactor power from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.2.4.1 REQUIREMENTS The drywell-to-suppression chamber differential pressure is regularly monitored to ensure that the required limits are satisfied. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency of this SR was developed based on operating experience relative to differential pressure variations during applicable MODES. Furthermore, the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal pressure condition.

REFERENCES 1. UFSAR, Section 5.2.3.3.

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Primary Containment Oxygen Concentration B 3.6.3.1 B 3.6 CONTAINMENT SYSTEMS B 3.6.3.1 Primary Containment Oxygen Concentration BASES BACKGROUND The primary containment is designed to withstand events that generate hydrogen either due to the zirconium metal water reaction in the core or due to radiolysis of reactor coolant. The primary method to control hydrogen is to inert the primary containment with nitrogen gas. With the primary containment inert, that is, oxygen concentration

< 4.0 volume percent (v/o), a combustible mixture cannot be present in the primary containment for any hydrogen concentration. The capability to inert the primary containment and maintain oxygen < 4.0 v/o works together with the Containment Atmosphere Dilution (CAD) System to mitigate events that produce hydrogen and oxygen. For example, an event that rapidly generates hydrogen from zirconium metal water reaction will result in excessive hydrogen in primary containment, but oxygen concentration will remain < 4.0 v/o and no combustion can occur. Long term generation of both hydrogen and oxygen from radiolytic decomposition of water is controlled by the CAD System.

This LCO ensures that oxygen concentration does not exceed 4.0 v/o during operation in the applicable conditions.

APPLICABLE The Reference 1 calculations assume that the primary SAFETY ANALYSES containment is inerted when a Design Basis loss of coolant accident (LOCA) occurs. Thus, the hydrogen assumed to be released to the primary containment as a result of metal water reaction in the reactor core will not produce combustible gas mixtures in the primary containment.

Oxygen, which is subsequently generated by radiolytic decomposition of water, is controlled by the CAD System.

Primary containment oxygen concentration satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii) (Ref. 2).

LCO The primary containment oxygen concentration is maintained

< 4.0 v/o to ensure that an event that produces any amount of hydrogen does not result in a combustible mixture inside primary containment.

APPLICABILITY The primary containment oxygen concentration must be within the specified limit when primary containment is inerted, except as allowed by the relaxations during startup and (continued)

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Primary Containment Oxygen Concentration B 3.6.3.1 BASES APPLICABILITY shutdown addressed below. The primary containment must be (continued) inert in MODE 1, since this is the condition with the highest probability of an event that could produce hydrogen.

Inerting the primary containment is an operational problem because it prevents containment access without an appropriate breathing apparatus. Therefore, the primary containment is inerted as late as possible in the plant startup and de-inerted as soon as possible in the plant shutdown. As long as reactor power is < 15% RTP, the potential for an event that generates significant hydrogen is low and the primary containment need not be inert.

Furthermore, the probability of an event that generates hydrogen occurring within the first 24 hours1 days 0.143 weeks 0.0329 months of a startup, or within the last 24 hours1 days 0.143 weeks 0.0329 months before a shutdown, is low enough that these "windows," when the primary containment is not inerted, are also justified. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months time period is a reasonable amount of time to allow plant personnel to perform inerting or de-inerting.

ACTIONS A.1 If oxygen concentration is Ž 4.0 v/o at any time while operating in MODE 1, with the exception of the relaxations allowed during startup and shutdown, oxygen concentration must be restored to < 4.0 v/o within 24 hours1 days 0.143 weeks 0.0329 months . The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is allowed when oxygen concentration is 2 4.0 v/o because of the availability of other hydrogen mitigating systems (e.g., the CAD System) and the low probability and long duration of an event that would generate significant amounts of hydrogen occurring during this period.

B.1 If oxygen concentration cannot be restored to within limits within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, power must be reduced to g 15% RTP within 8 hours0.333 days 0.0476 weeks 0.011 months . The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is reasonable, based on operating experience, to reduce reactor power from full power conditions in an orderly manner and without challenging plant systems.

(continued)

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Primary Containment Oxygen Concentration B 3.6.3.1 BASES (continued)

SURVEILLANCE SR 3.6.3.1.1 REQUIREMENTS The primary containment must be determined to be inert by verifying that oxygen concentration is < 4.0 v/o. The 7 day Frequency is based on the slow rate at which oxygen concentration can change and on other indications of abnormal conditions (which would lead to more frequent checking by operators in accordance with plant procedures).

Also, this Frequency has been shown to be acceptable through operating experience.

REFERENCES 1. UFSAR, Section 5.2.3.8.

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CAD System B 3.6.3.2 B 3.6 CONTAINMENT SYSTEMS B 3.6.3.2 Containment Atmosphere Dilution (CAD) System BASES BACKGROUND The CAD System functions to maintain combustible gas concentrations within the primary containment at or below the flammability limits following a postulated loss of coolant accident (LOCA) by diluting hydrogen and oxygen with nitrogen. To ensure that a combustible gas mixture does not occur, oxygen concentration is kept < 4.0 volume percent (v/o).

The CAD System is manually initiated and consists of two independent, 100% capacity subsystems. Each subsystem includes a liquid nitrogen supply tank, ambient vaporizer, electric heater, and connected piping to supply the drywell and suppression chamber volumes. The CAD subsystems are utilized for normal makeup. The CAD subsystems also provide the pneumatic supply requirements of instruments and controls inside the drywell including the long term (100 days) pneumatic supply requirements of the Automatic Depressurization System (ADS) valves and accumulators following a LOCA. In addition, separate lines from each liquid nitrogen storage tank with separate ambient heat exchangers and pressure control valves provides the pneumatic supply for the CAD subsystem pneumatically operated valves. The nitrogen storage tanks each contain S1400 gal, which is adequate for 3 days of CAD subsystem operation. This provides sufficient time to replenish the tanks for the long term supply requirements.

The CAD System operates in conjunction with emergency operating procedures that are used to reduce primary containment pressure periodically during CAD System operation. This combination results in a feed and bleed approach to maintaining hydrogen and oxygen concentrations below combustible levels.

APPLICABLE To evaluate the potential for hydrogen and oxygen SAFETY ANALYSES accumulation in primary containment following a LOCA, hydrogen and oxygen generation is calculated (as a function of time following the initiation of the accident). The assumptions stated in Reference 1 are used to maximize the amount of hydrogen and oxygen generated. The calculation confirms that when the mitigating systems are actuated in accordance with emergency operating procedures, the peak oxygen concentration in primary containment is < 4.0 v/o (Ref. 2).

(continued)

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CAD System B 3.6.3.2 BASES APPLICABLE Hydrogen and oxygen may accumulate within primary SAFETY ANALYSES containment following a LOCA as a result of:

(continued)

a. A metal water reaction between the zirconium fuel rod cladding and the reactor coolant; or

b. Radiolytic decomposition of water in the Reactor Coolant System.

The CAD System satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii) (Ref. 3).

LCO Two CAD subsystems must be OPERABLE. This ensures operation of at least one CAD subsystem in the event of a worst case single active component failure. Operation of at least one CAD subsystem is designed to maintain primary containment post-LOCA oxygen concentration < 4.0 v/o for 3 days.

APPLICABILITY In MODES 1 and 2, the CAD System is required to maintain the oxygen concentration within primary containment below the flammability limit of 5.0 v/o following a LOCA. This ensures that the relative leak tightness of primary containment is adequate and prevents damage to safety related equipment and instruments located within primary containment.

In MODE 3, both the hydrogen and oxygen production rates and the total amounts produced after a LOCA would be less than those calculated for the Design Basis LOCA. Thus, if the analysis were to be performed starting with a LOCA in MODE 3, the time to reach a flammable concentration would be extended beyond the time conservatively calculated for MODES 1 and 2. The extended time would allow hydrogen removal from the primary containment atmosphere by other means and also allow repair of an inoperable CAD subsystem, if CAD were not available. Therefore, the CAD System is not required to be OPERABLE in MODE 3.

In MODES 4 and 5, the probability and consequences of a LOCA are reduced due to the pressure and temperature limitations of these MODES. Therefore, the CAD System is not required to be OPERABLE in MODES 4 and 5.

(continued)

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CAD System B 3.6.3.2_

BASES (continued)

ACTIONS A.1 If one CAD subsystem is inoperable, it must be restored to OPERABLE status within 30 days. In this Condition, the remaining OPERABLE CAD subsystem is adequate to perform the oxygen control function. However, the overall reliability is reduced because a single active failure in the OPERABLE subsystem could result in reduced oxygen control capability.

The 30 day Completion Time is based on the low probability of the occurrence of a LOCA that would generate hydrogen and oxygen in amounts capable of exceeding the flammability limit, the amount of time available after the event for operator action to prevent exceeding this limit, and the availability of the OPERABLE CAD subsystem and other hydrogen mitigating systems.

Required Action A.1 has been modified by a Note that indicates that the provisions of LCO 3.0.4 are not applicable. As a result, a MODE change is allowed when one CAD subsystem is inoperable. This allowance is provided because of the low probability of the occurrence of a LOCA that would generate hydrogen and oxygen in amounts capable of exceeding the flammability limit, the low probability of the failure of the OPERABLE subsystem, the amount of time available after a postulated LOCA for operator action to prevent exceeding the flammability limit, and the availability of other hydrogen mitigating systems.

B.1 and B.2 With two CAD subsystems inoperable, the ability to perform the hydrogen control function via alternate capabilities must be verified by administrative means within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The alternate hydrogen control capabilities are provided by the Primary Containment Inerting System. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time allows a reasonable period of time to verify that a loss of hydrogen control function does not exist. In addition, the alternate hydrogen control system capability must be verified once per 12 hours0.5 days 0.0714 weeks 0.0164 months thereafter to ensure its continued availability. Both the initial verification and all subsequent verifications may be performed as an administrative check by examining logs or other information to determine the availability of the alternate hydrogen control system. It does not mean to perform the Surveillances needed to demonstrate OPERABILITY of the alternate hydrogen control system. If the ability to perform the hydrogen control function is maintained, continued operation is permitted with two CAD subsystems (continued)

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CAD System B 3.6.3.2 BASES ACTIONS B.1 and B.2 (continued) inoperable for up to 7 days. Seven days is a reasonable time to allow two CAD subsystems to be inoperable because the hydrogen control function is maintained and because of the low probability of the occurrence of a LOCA that would generate hydrogen in amounts capable of exceeding the flammability limit.

C.1 If any Required Action cannot be met within the associated Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours0.5 days 0.0714 weeks 0.0164 months .

The allowed Completion Time of 12 hours0.5 days 0.0714 weeks 0.0164 months is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.3.2.1 REQUIREMENTS Verifying that there is Ž 1400 gal of liquid nitrogen supply in each CAD subsystem will ensure at least 3 days of post LOCA CAD operation. This minimum volume of liquid nitrogen allows sufficient time after an accident to replenish the nitrogen supply for long term inerting. This is verified every 31 days to ensure that the system is capable of performing its intended function when required. The 31 day Frequency is based on operating experience, which has shown 31 days to be an acceptable period to verify the liquid nitrogen supply and on the availability of other hydrogen mitigating systems.

SR 3.6.3.2.2 Verifying the correct alignment for manual, power operated, and automatic valves in each of the CAD subsystem flow paths provides assurance that the proper flow paths exist for system operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves were verified to be in the correct position prior to locking, sealing, or securing.

(continued)

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CAD System B 3.6.3.2 BASES SURVEILLANCE SR 3.6.3.2.2 (continued)

REQUIREMENTS A valve is also allowed to be in the nonaccident position provided it can be aligned to the accident position within the time assumed in the accident analysis. This is acceptable because the CAD System is manually initiated.

This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position.

The 31 day Frequency is appropriate because the valves are operated under procedural control, improper valve position would only affect a single subsystem, the probability of an event requiring initiation of the system is low, and the system is a manually initiated system.

REFERENCES 1. Safety Guide 7, March 10, 1971.

2. UFSAR, Section 5.2.3.8.3.

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Secondary Containment B 3.6.4.L B 3.6 CONTAINMENT SYSTEMS B 3.6.4.1 Secondary Containment BASES BACKGROUND The function of the secondary containment is to contain, dilute, and hold up fission products that may leak from primary containment following a Design Basis Accident (DBA).

In conjunction with operation of the Standby Gas Treatment (SGT) System and closure of certain valves whose lines penetrate the secondary containment, the secondary containment is designed to reduce the activity level of the fission products prior to release to the environment and to isolate and contain fission products that are released during certain operations that take place inside primary containment, when primary containment is not required to be OPERABLE, or that take place outside primary containment.

The secondary containment is a structure that surrounds the primary containment and is designed to provide secondary containment for postulated loss-of-coolant accidents inside the primary containment. The Secondary Containment also surrounds the refueling facilities and is designed to provide primary containment for the postulated refueling accident. This structure forms a control volume that serves to hold up and dilute the fission products. It is possible for the pressure in the control volume to rise relative to the environmental pressure (e.g., due to pump and motor heat load additions). To prevent ground level exfiltration while allowing the secondary containment to be designed as a conventional structure, the secondary containment requires support systems to maintain the control volume pressure at less than the external pressure. Requirements for these systems are specified separately in LCO 3.6.4.2, "Secondary Containment Isolation Valves (SCIVs)," and LCO 3.6.4.3, "Standby Gas Treatment (SGT) System."

APPLICABLE There are two principal accidents for which credit is taken SAFETY ANALYSES for secondary containment OPERABILITY. These are a loss of coolant accident (LOCA) (Ref. 1) and a refueling accident inside secondary containment (Ref. 2). The secondary containment performs no active function in response to each of these limiting events; however, its leak tightness is required to ensure that fission products entrapped within the secondary containment structure will be treated by the SGT System prior to discharge to the environment.

Secondary containment satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii) (Ref. 3).

(continued)

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Secondary Containment B 3.6.4.L BASES (continued)

LCO An OPERABLE secondary containment provides a control volume into which fission products that leak from primary containment, or are released from the reactor coolant pressure boundary components located in secondary containment, or are released directly to the secondary containment as a result of a refueling accident, can be processed prior to release to the environment. For the secondary containment to be considered OPERABLE, it must have adequate leak tightness to ensure that the required vacuum can be established and maintained.

APPLICABILITY In MODES 1, 2, and 3, a LOCA could lead to a fission product release to primary containment that leaks to secondary containment. Therefore, secondary containment OPERABILITY is required during the same operating conditions that require primary containment OPERABILITY.

In MODES 4 and 5, the probability and consequences of the LOCA are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining secondary containment OPERABLE is not required in MODE 4 or 5 to ensure a control volume, except for other situations for which significant releases of radioactive material can be postulated, such as during operations with a potential for draining the reactor vessel (OPDRVs), during CORE ALTERATIONS, or during movement of irradiated fuel assemblies in the secondary containment.

ACTIONS A.1 If secondary containment is inoperable, it must be restored to OPERABLE status within 4 hours0.167 days 0.0238 weeks 0.00548 months . The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time provides a period of time to correct the problem that is commensurate with the importance of maintaining secondary containment during MODES 1, 2, and 3. This time period also ensures that the probability of an accident (requiring secondary containment OPERABILITY) occurring during periods where secondary containment is inoperable is minimal.

B.1 and B.2 If secondary containment cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours0.5 days 0.0714 weeks 0.0164 months and to MODE 4 within 36 hours1.5 days 0.214 weeks 0.0493 months . The (continued)

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Secondary Containment B 3.6.4.W BASES ACTIONS B.1 and B.2 (continued) allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

C.1, C.2, and C.3 Movement of irradiated fuel assemblies in the secondary containment, CORE ALTERATIONS, and OPDRVs can be postulated to cause fission product release to the secondary containment. In such cases, the secondary containment is the only barrier to release of fission products to the environment. CORE ALTERATIONS and movement of irradiated fuel assemblies must be immediately suspended if the secondary containment is inoperable.

Suspension of these activities shall not preclude completing an action that involves moving a component to a safe position. Also, action must be immediately initiated to suspend OPDRVs to minimize the probability of a vessel draindown and subsequent potential for fission product release. Actions must continue until OPDRVs are suspended.

LCO 3.0.3 is not applicable in MODES 4 or 5. However, since irradiated fuel assembly movement can occur in MODE 1, 2, or 3, Required Action C.1 has been modified by a Note stating that LCO 3.0.3 is not applicable. If moving irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, in either case, inability to suspend movement of irradiated fuel assemblies would not be a sufficient reason to require a reactor shutdown.

SURVEILLANCE SR 3.6.4.1.1 REQUIREMENTS This SR ensures that the secondary containment boundary is sufficiently leak tight to preclude exfiltration under expected wind conditions. Momentary transients on the installed instrumentation due to gusty wind conditions are considered acceptable and not cause for failure of this SR.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency of this SR was developed based on operating experience related to secondary containment vacuum variations during the applicable MODES and the low probability of a DBA occurring between surveillances.

(continued)

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Secondary Containment B 3.6.4.L BASES SURVEILLANCE SR 3.6.4.1.1 (continued)

REQUIREMENTS Furthermore, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal secondary containment vacuum condition.

SR 3.6.4.1.2 and SR 3.6.4.1.3 Verifying that secondary containment equipment hatches and one access door in each access opening are closed ensures that the infiltration of outside air of such a magnitude as to prevent maintaining the desired negative pressure does not occur. Verifying that all such openings are closed provides adequate assurance that exfiltration from the secondary containment will not occur. SR 3.6.4.1.2 also requires equipment hatches to be sealed. In this application, the term "sealed" has no connotation of leak tightness. Maintaining secondary containment OPERABILITY requires verifying one door in the access opening is closed.

An access opening contains one inner and one outer door. In some cases, secondary containment access openings are shared such that a secondary containment barrier may have multiple outer doors. The intent is to not breach the secondary containment at any time when secondary containment is required. This is achieved by maintaining the inner or outer portion of the barrier closed at all times. However, all secondary containment access doors are normally kept closed, except when the access opening is being used for entry and exit or when maintenance is being performed on an access opening.

The 31 day Frequency of SR 3.6.4.1.2 is considered adequate, based on operating experience, and in view of strict administrative procedures required to open a hatch. The 31 day Frequency for SR 3.6.4.1.3 has been shown to be adequate, based on operating experience, and in view of local indication of door status and strict administrative procedures required to be followed for entry and exit.

SR 3.6.4.1.4 The SGT System exhausts the secondary containment atmosphere to the environment through appropriate treatment equipment.

To ensure that all fission products released to the secondary containment are treated, SR 3.6.4.1.4 verifies that a pressure in the secondary containment that is less (continued)

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Secondary Containment B 3.6.4.1L BASES SURVEILLANCE SR 3.6.4.1.4 (continued)

REQUIREMENTS than the lowest postulated pressure external to the secondary containment boundary can be maintained. When the SGT System is operating as designed, the maintenance of secondary containment pressure cannot be accomplished if the secondary containment boundary is not intact. SR 3.6.4.1.4 demonstrates that the pressure in the secondary containment can be maintained Ž 0.25 inches of vacuum water gauge for 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months using one SGT subsystem at a flow rate

6000 cfm under calm wind conditions. Calm wind conditions will result in little, if any, infiltration to the secondary containment. Therefore, if the test is performed at other wind conditions and the results are acceptable, this test may be considered met. This test method is acceptable since extreme wind conditions are only expected to be present for a few hours a year. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months test period allows secondary containment to be in thermal equilibrium at steady state conditions. The primary purpose of this SR is to ensure secondary containment boundary integrity. The secondary purpose of this SR is to ensure that the SGT subsystem being tested functions as designed. There is a separate LCO with Surveillance Requirements which serves the primary purpose of ensuring OPERABILITY of the SGT System. This SR need not be performed for each SGT subsystem. The SGT subsystem used for this Surveillance is staggered to ensure that in addition to the requirements of LCO 3.6.4.3, either SGT subsystem will perform this test. The inoperability of the SGT subsystem does not necessarily constitute a failure of this Surveillance relative to the secondary containment OPERABILITY. Operating experience has shown the secondary containment boundary usually passes this Surveillance when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

REFERENCES 1. UFSAR, Section 14.6.1.3.

2. UFSAR, Section 14.6.1.4.

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SCIVs B 3.6.4.2-B 3.6 CONTAINMENT SYSTEMS B 3.6.4.2 Secondary Containment Isolation Valves (SCIVs)

BASES BACKGROUND The function of the SCIVs, in combination with other accident mitigation systems, is to limit fission product release during and following postulated Design Basis Accidents (DBAs) (Refs. 1 and 2). Secondary containment isolation within the time limits specified for those isolation valves designed to close automatically ensures that fission products that leak from primary containment following a DBA, or that are released during certain operations when primary containment is not required to be OPERABLE or take place outside primary containment, are maintained within the secondary containment boundary.

The OPERABILITY requirements for SCIVs help ensure that an adequate secondary containment boundary is maintained during and after an accident by minimizing potential paths to the environment. These isolation devices consist of either passive devices or active (automatic) devices. Manual valves, de-activated automatic valves secured in their closed position (including check valves with flow through the valve secured), and blind flanges are considered passive devices.

Automatic SCIVs close on a secondary containment isolation signal to establish a boundary for untreated radioactive material within secondary containment following a DBA or other accidents.

Other penetrations are isolated by the use of valves in the closed position or blind flanges.

APPLICABLE The SCIVs must be OPERABLE to ensure the secondary SAFETY ANALYSES containment barrier to fission product releases is established. The principal accidents for which the secondary containment boundary is required are a loss of coolant accident (Ref. 1) and a refueling accident inside secondary containment (Ref. 2). The secondary containment performs no active function in response to either of these limiting events, but the boundary established by SCIVs is required to ensure that leakage from the primary containment is processed by the Standby Gas Treatment (SGT) System before being released to the environment.

(continued)

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SCIVs B 3.6.4.2 BASES APPLICABLE Maintaining SCIVs OPERABLE with isolation times within SAFETY ANALYSES limits ensures that fission products will remain trapped (continued) inside secondary containment so that they can be treated by the SGT System prior to discharge to the environment.

SCIVs satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii)

(Ref. 3).

LCO SCIVs form a part of the secondary containment boundary.

The SCIV safety function is related to control of offsite radiation releases resulting from DBAs.

The power operated automatic isolation valves are considered OPERABLE when their isolation times are within limits and the valves actuate on an automatic isolation signal. The valves covered by this LCO, along with their associated stroke times, are listed in Reference 4.

The normally closed isolation valves or blind flanges are considered OPERABLE when manual valves are closed or open in accordance with appropriate administrative controls, automatic SCIVs are de-activated and secured in their closed position, and blind flanges are in place. These passive isolation valves or devices are listed in Reference 4.

APPLICABILITY In MODES 1, 2, and 3, a DBA could lead to a fission product release to the primary containment that leaks to the secondary containment. Therefore, the OPERABILITY of SCIVs is required.

In MODES 4 and 5, the probability and consequences of these events are reduced due to pressure and temperature limitations in these MODES. Therefore, maintaining SCIVs OPERABLE is not required in MODE 4 or 5, except for situations under which significant radioactive releases can be postulated, such as during operations with a potential for draining the reactor vessel (OPDRVs), during CORE ALTERATIONS, or during movement of irradiated fuel assemblies in the secondary containment. Moving irradiated fuel assemblies in the secondary containment may also occur in MODES 1, 2, and 3.

ACTIONS The ACTIONS are modified by three Notes. The first Note allows penetration flow paths to be unisolated intermittently under administrative controls. These controls consist of stationing a dedicated operator, who is (continued)

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SCIVs B 3.6.4.2 BASES ACTIONS in continuous communication with the control room, at the (continued) controls of the isolation device. In this way, the penetration can be rapidly isolated when a need for secondary containment isolation is indicated.

The second Note provides clarification that, for the purpose of this LCO, separate Condition entry is allowed for each penetration flow path. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable SCIV. Complying with the Required Actions may allow for continued operation, and subsequent inoperable SCIVs are governed by subsequent Condition entry and application of associated Required Actions.

The third Note ensures appropriate remedial actions are taken, if necessary, if the affected system(s) are rendered inoperable by an inoperable SCIV.

A.1 and A.2 In the event that there are one or more penetration flow paths with one SCIV inoperable, the affected penetration flow path(s) must be isolated. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure.

Isolation barriers that meet this criterion are a closed and de-activated automatic SCIV, a closed manual valve, and a blind flange. For penetrations isolated in accordance with Required Action A.1, the device used to isolate the penetration should be the closest available device to secondary containment. The Required Action must be completed within the 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time. The specified time period is reasonable considering the time required to isolate the penetration, and the probability of a DBA, which requires the SCIVs to close, occurring during this short time is very low.

For affected penetrations that have been isolated in accordance with Required Action A.1, the affected penetration must be verified to be isolated on a periodic basis. This is necessary to ensure that secondary containment penetrations required to be isolated following an accident, but no longer capable of being automatically isolated, will be in the isolation position should an event occur. The Completion Time of once per 31 days is appropriate because the valves are operated under administrative controls and the probability of their (continued)

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SCIVs B 3.6.4.2 BASES ACTIONS A.1 and A.2 (continued) misalignment is low. This Required Action does not require any testing or device manipulation. Rather, it involves verification that the affected penetration remains isolated.

Required Action A.2 is modified by two Notes. Note 1 applies to devices located in high radiation areas and allows them to be verified closed by use of administrative controls.

Allowing verification by administrative controls is considered acceptable, since access to these areas is typically restricted. Note 2 applies to isolation devices that are locked, sealed, or otherwise secured in position and allows these devices to be verified closed by use of administrative means. Allowing verification by administrative means is considered acceptable, since the function of locking, sealing, or securing components is to ensure that these devices are not inadvertently repositioned. Therefore, the probability of misalignment, once they have been verified to be in the proper position, is low.

B.1 With two SCIVs in one or more penetration flow paths inoperable, the affected penetration flow path must be isolated within 4 hours0.167 days 0.0238 weeks 0.00548 months . The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure.

Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, and a blind flange. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is reasonable considering the time required to isolate the penetration and the probability of a DBA, which requires the SCIVs to close, occurring during this short time, is very low.

The Condition has been modified by a Note stating that Condition B is only applicable to penetration flow paths with two isolation valves. This clarifies that only Condition A is entered if only one SCIV is inoperable in multiple penetrations.

C.1 and C.2 If any Required Action and associated Completion Time cannot be met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours0.5 days 0.0714 weeks 0.0164 months and to MODE 4 (continued)

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SCIVs..

B 3.6.4.

BASES ACTIONS C.1 and C.2 (continued) within 36 hours1.5 days 0.214 weeks 0.0493 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

D.1, D.2, and D.3 If any Required Action and associated Completion Time are not met, the plant must be placed in a condition in which the LCO does not apply. If applicable, CORE ALTERATIONS and the movement of irradiated fuel assemblies in the secondary containment must be immediately suspended. Suspension of these activities shall not preclude completion of movement of a component to a safe position. Also, if applicable, actions must be immediately initiated to suspend OPDRVs in order to minimize the probability of a vessel draindown and the subsequent potential for fission product release.

Actions must continue until OPDRVs are suspended.

LCO 3.0.3 is not applicable while in MODE 4 or 5. However, since irradiated fuel assembly movement can occur in MODE 1, 2, or 3, Required Action D.1 has been modified by a Note stating that LCO 3.0.3 is not applicable. If moving irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving fuel while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, in either case, inability to suspend movement of irradiated fuel assemblies would not be a sufficient reason to require a reactor shutdown.

SURVEILLANCE SR 3.6.4.2.1 REQUIREMENTS This SR verifies that each secondary containment manual isolation valve and blind flange that is not locked, sealed, or otherwise secured and is required to be closed during accident conditions is closed. The SR helps to ensure that post accident leakage of radioactive fluids or gases outside of the secondary containment boundary is within design limits. This SR does not require any testing or valve manipulation. Rather, it involves verification that those SCIVs in secondary containment that are capable of being mispositioned are in the correct position.

(continued)

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SCIVs B 3.6.4.2 BASES SURVEILLANCE SR 3.6.4.2.1 (continued)

REQUIREMENTS Since these SCIVs are readily accessible to personnel during normal operation and verification of their position is relatively easy, the 31 day Frequency was chosen to provide added assurance that the SCIVs are in the correct positions.

This SR does not apply to valves that are locked, sealed, or otherwise secured in the closed position, since these were verified to be in the correct position upon locking, sealing, or securing.

Two Notes have been added to this SR. The first Note applies to valves and blind flanges located in high radiation areas and allows them to be verified by use of administrative controls. Allowing verification by administrative controls is considered acceptable, since access to these areas is typically restricted during MODES 1, 2, and 3 for ALARA reasons. Therefore, the probability of misalignment of these SCIVs, once they have been verified to be in the proper position, is low.

A second Note has been included to clarify that SCIVs that are open under administrative controls are not required to meet the SR during the time the SCIVs are open. These controls consist of stationing a dedicated operator at the controls of the valve who is in continuous communication with the control room. In this way, the penetration can be rapidly isolated when a need for secondary containment isolation is indicated.

SR 3.6.4.2.2 Verifying that the isolation time of each power operated, automatic SCIV is within limits is required to demonstrate OPERABILITY. The isolation time test ensures that the SCIV will isolate in a time period less than or equal to that assumed in the safety analyses. The Frequency of this SR is 92 days.

SR 3.6.4.2.3 Verifying that each automatic SCIV closes on a secondary containment isolation signal is required to prevent leakage of radioactive material from secondary containment following a DBA or other accidents. This SR ensures that each automatic SCIV will actuate to the isolation position on a secondary containment isolation signal. The LOGIC SYSTEM (continued)

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SCIVs B 3.6.4.2_

BASES SURVEILLANCE SR 3.6.4.2.3 (continued)

REQUIREMENTS FUNCTIONAL TEST in LCO 3.3.6.2, "Secondary Containment Isolation Instrumentation," overlaps this SR to provide complete testing of the safety function. The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency.

Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

REFERENCES 1. UFSAR, Section 14.6.1.3.

2. UFSAR, Section 14.6.1.4.

4. Technical Requirements Manual.

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SGT System B 3.6.4.3 B 3.6 CONTAINMENT SYSTEMS B 3.6.4.3 Standby Gas Treatment (SGT) System BASES BACKGROUND The SGT System is required by UFSAR, Section 16.6 (Ref. 1).

The function of the SGT System is to ensure that radioactive materials that leak from the primary containment into the secondary containment following a Design Basis Accident (DBA) are filtered and adsorbed prior to exhausting to the environment.

The SGT System consists of two fully redundant subsystems, each with its own set of ductwork, dampers, charcoal filter assembly, centrifugal fan and controls. The SGT subsystems share a common inlet line. The inlet line is connected through separate valved connections to the reactor building above the refuel floor, reactor building below refuel floor, primary containment drywell and suppression chamber, HPCI turbine gland seal exhauster, main steam leak collection system and Auxiliary Gas Treatment System. Both 100%

capacity SGT subsystem fans exhaust to the elevated release point (the main stack), through a common exhaust duct. The SGT subsystem fans are designed to automatically start upon a secondary containment isolation signal.

The fan suctions are cross connected by a single line and two normally opened manual cross tie valves to accommodate decay heat removal. Air for decay heat removal enters the idle SGT subsystem from the SGT room via a motor operated valve and restricting orifice. The air is drawn through the filter, removing the decay heat from the idle subsystem filters, passes through the cross tie line to the opposite operating SGT subsystem fan, and is exhausted to the main stack.

Each SGT filter assembly consists of (components listed in order of the direction of the air flow):

a. A demister;

b. An electric heater;

c. A prefilter;

d. A high efficiency particulate air (HEPA) filter; (continued)

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SGT System B 3.6.4.3_

BASES BACKGROUND e. A charcoal adsorber; and (continued)

f. A second HEPA filter.

The SGT System equipment and components are sized to reduce and maintain the secondary containment at a negative pressure of 0.25 inches water gauge when the system is in operation under neutral wind conditions and the SGT fans exhausting at a rate of 6,000 cfm.

The demister is provided to remove entrained water in the air, while the electric heater reduces the relative humidity of the airstream to less than 70% (Ref. 2). The prefilter removes large particulate matter, while the HEPA filter removes fine particulate matter and protects the charcoal from fouling. The charcoal adsorber removes gaseous elemental iodine and organic iodides, and the final HEPA filter collects any carbon fines exhausted from the charcoal adsorber.

The SGT System automatically starts and operates in response to actuation signals indicative of conditions or an accident that could require operation of the system. Following initiation, both SGT subsystem fans start. Upon verification that both subsystems are operating, one subsystem is normally shut down.

APPLICABLE The design basis for the SGT System is to mitigate the SAFETY ANALYSES consequences of a loss of coolant accident and refueling accidents (Ref. 3). For all events analyzed, the SGT System is shown to be automatically initiated to reduce, via filtration and adsorption, the radioactive material released to the environment.

The SGT System satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii) (Ref. 4).

LCO Following a DBA, a minimum of one SGT subsystem is required to maintain the secondary containment at a negative pressure with respect to the environment and to process gaseous releases. Meeting the LCO requirements for two OPERABLE subsystems ensures operation of at least one SGT subsystem in the event of a single active failure. An OPERABLE SGT subsystem consists of a demister, heater, prefilter, HEPA filter, charcoal adsorber, a final HEPA filter, centrifugal fan, and associated ductwork, dampers, valves and controls.

(continued)

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SGT System B 3.6.4.3_

BASES (continued)

APPLICABILITY In MODES 1, 2, and 3, a DBA could lead to a fission product release to primary containment that leaks to secondary containment. Therefore, SGT System OPERABILITY is required during these MODES.

In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining the SGT System in OPERABLE status is not required in MODE 4 or 5, except for other situations under which significant releases of radioactive material can be postulated, such as during operations with a potential for draining the reactor vessel (OPDRVs), during CORE ALTERATIONS, or during movement of irradiated fuel assemblies in the secondary containment.

ACTIONS A.1 With one SGT subsystem inoperable, the inoperable subsystem must be restored to OPERABLE status in 7 days. In this Condition, the remaining OPERABLE SGT subsystem is adequate to perform the required radioactivity release control function. However, the overall system reliability is reduced because a single failure in the OPERABLE subsystem could result in the radioactivity release control function not being adequately performed. The 7 day Completion Time is based on consideration of such factors as the availability of the OPERABLE redundant SGT subsystem and the low probability of a DBA occurring during this period.

B.1 and B.2 If the SGT subsystem cannot be restored to OPERABLE status within the required Completion Time in MODE 1, 2, or 3, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours0.5 days 0.0714 weeks 0.0164 months and to MODE 4 within 36 hours1.5 days 0.214 weeks 0.0493 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

(continued)

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SGT System B 3.6.4.3 BASES ACTIONS C.1, C.2.1, C.2.2, and C.2.3 (continued)

During movement of irradiated fuel assemblies, in the secondary containment, during CORE ALTERATIONS, or during OPDRVs, when Required Action A.1 cannot be completed within the required Completion Time, the OPERABLE SGT subsystem should immediately be placed in operation. This action ensures that the remaining subsystem is OPERABLE, that no failures that could prevent automatic actuation have occurred, and that any other failure would be readily detected.

An alternative to Required Action C.1 is to immediately suspend activities that represent a potential for releasing radioactive material to the secondary containment, thus placing the plant in a condition that minimizes risk. If applicable, CORE ALTERATIONS and movement of irradiated fuel assemblies must immediately be suspended. Suspension of these activities must not preclude completion of movement of a component to a safe position. Also, if applicable, actions must immediately be initiated to suspend OPDRVs in order to minimize the probability of a vessel draindown and subsequent potential for fission product release. Actions must continue until OPDRVs are suspended.

LCO 3.0.3 is not applicable in MODE 4 or 5. However, since irradiated fuel assembly movement can occur in MODE 1, 2, or 3, the Required Actions of Condition C have been modified by a Note stating that LCO 3.0.3 is not applicable. If moving irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations.

Therefore, in either case, inability to suspend movement of irradiated fuel assemblies would not be a sufficient reason to require a reactor shutdown.

D.1 If both SGT subsystems are inoperable in MODE 1, 2, or 3, the SGT System may not be capable of supporting the required radioactivity release control function. Therefore, action is required to enter LCO 3.0.3 immediately.

(continued)

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SGT System B 3.6.4.3 BASES ACTIONS E.1, E.2, and E.3 (continued)

When two SGT subsystems are inoperable, if applicable, CORE ALTERATIONS and movement of irradiated fuel assemblies in secondary containment must immediately be suspended.

Suspension of these activities shall not preclude completion of movement of a component to a safe position. Also, if applicable, actions must immediately be initiated to suspend OPDRVs in order to minimize the probability of a vessel draindown and subsequent potential for fission product release. Actions must continue until OPDRVs are suspended.

LCO 3.0.3 is not applicable in MODE 4 or 5. However, since irradiated fuel assembly movement can occur in MODE 1, 2, or 3, Required Action E.1 has been modified by a Note stating that LCO 3.0.3 is not applicable. If moving irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, in either case, inability to suspend movement of irradiated fuel assemblies would not be a sufficient reason to require a reactor shutdown.

SURVEILLANCE SR 3.6.4.3.1 REQUIREMENTS Operating each SGT subsystem fan for ; 10 continuous hours ensures that both subsystems are OPERABLE and that all associated controls are functioning properly. It also ensures that blockage, fan or motor failure, or excessive vibration can be detected for corrective action. Operation with the heaters on for Ž 10 continuous hours every 31 days eliminates moisture on the adsorbers and HEPA filters. The 31 day Frequency was developed in consideration of the known reliability of fan motors and controls and the redundancy available in the system.

SR 3.6.4.3.2 This SR verifies that the required SGT filter testing is performed in accordance with the Ventilation Filter Testing Program (VFTP). The VFTP includes testing HEPA filter performance, charcoal adsorber efficiency, minimum system flow rate, and the physical properties of the activated charcoal (general use and following specific operations).

Specific test frequencies and additional information are discussed in detail in the VFTP.

(continued)

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SGT System B 3.6.4.3_

BASES SURVEILLANCE SR 3.6.4.3.3 REQUIREMENTS (continued) This SR verifies that each SGT subsystem starts on receipt of an actual or simulated initiation signal. In addition, the OPERABILITY of each SGT decay heat cooling valve is verified to ensure the valve closes on subsystem initiation (interlocked with the suction valve) and opens when shutdown. This will ensure the mitigation function as well as the decay heat cooling mode of each SGT subsystem is available. While this Surveillance can be performed with the reactor at power, operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.6.2, "Secondary Containment Isolation Instrumentation," overlaps this SR to provide complete testing of the safety function. Therefore, the Frequency was found to be acceptable from a reliability standpoint.

SR 3.6.4.3.4 This SR verifies that the filter cooling cross-tie valves are OPERABLE. This ensures that the decay heat cooling mode of SGT System operation is available. The 24 month Frequency has been shown to be adequate, based on operating experience, and in view of the strict administrative controls required for entry into the area of these valves.

REFERENCES 1. UFSAR, Section 16.6.

2. UFSAR, Section 5.3.3.4.

3. UFSAR, Section 14.6.