Text

Transmittal of Revision 14 to the Technical Specification Bases
	ML12166A135
Person / Time
Site:	Clinton
Issue date:	06/04/2012
From:	Noll W; Exelon Generation Co
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	U-604075
	Download: ML12166A135 (270)
	v • d • e

A Exeton Generation.

Clinton Power Station 8401 Power Road Clinton, IL 61727 U-604075 10 CFR 50.36 June 4, 2012 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555-0001 Clinton Power Station, Unit 1 Facility Operating License NRC Docket No. 50-461

Subject:

Transmittal of Revision 14 to the Clinton Power Station Technical Specification Bases In accordance with Clinton Power Station (CPS) Technical Specification 5.5.11, 'Technical Specification (TS) Bases Control Program," Exelon Generation Company (EGC), LLC is transmitting the revised pages constituting Revision 14 to the CPS TS Bases. The changes associated with this revision were processed in accordance with CPS TS 5.5.11.

Compliance with CPS TS 5.5.11 requires updates to the TS Bases to be submitted to the NRC at a frequency consistent with 10 CFR 50.71, "Maintenance of records, making of reports," paragraph (e).

There are no regulatory commitments in this letter.

Should you have any questions concerning this information, please contact Mr. Jim Peterson at (217) 937-2810.

Re William G. Noll Site Vice President Clinton Power Station JLP/blf - Revision 14 Bases Page Listing - Revision 14 Bases Pages

U.S. Nuclear Regulatory Commission U-604075 Page 2 of 2 cc: Regional Administrator, Region III (without Attachments)

NRC Senior Resident Inspector - Clinton Power Station (without Attachments)

Attachment 1 to U-604075 Revision 14 Bases Page Listing Bases Rev. 14-1 B3.3-45 B3.3-214 B3.6-31 B3.4-43 B3.3-46 B3.3-219 B3.6-34 B3.4-48 B3.3-47 B3.3-220 B3.6-38 B3.5-14b B3.3-48 B3.3-221 B3.6-42 B3.5-20a B3.3-58 B3.3-228 B3.6-43 B3.6-58b B3.3-59 B3.3-229 B3.6-45 B3.9-25 B3.3-63 B3.3-235 B3.6-46 B3.9-29 B3.3-64 B3.3-236 B3.6-47 Bases Rev. 14-2 83.3-72 B3.4-7 B3.6-52 TOC iv B3.3-73 B3.4-11 B3.6-55 TOC v B3.3-74 B3.4-16 B3.6-58a TOC vi B3.3-75 B3.4-21 B3.6-63 B3.1-19 B3.3-82 B3.4-22 B3.6-64 B3.1-26 83.3-83 B3.4-27 83.6-65 B3.1-32 83.3-84 B3.4-35 B3.6-76 B3.1-36 B3.3-119 B3.4-38 B3.6-77 B3.1-40 B3.3-120 B3.4-42 B3.6-81 B3.1-41 B3.3-120a 83.4-47 83.6-82 B3.1-42 63.3-120b 83.4-52 83.6-88 B3.1-43 B3.3-121 B3.4-58 B3.6-88b B3.1-47 B3.3-132 B3.4-60 83.6-94 63.1-48 B3.3-133 B3.4-61 83.6-95 B3.2-4 B3.3-134 B3.4-62 B3.6-101 B3.2-8 B3.3-170 B3.4-63 B3.6-101 a B3.2-11 B3.3-171 B3.4-64 B3.6-105 B3.3-23 B3.3-172 B3.5-10 B3.6-105a B3.3-24 B3.3-173 B3.5-11 13.6-105b B3.3-25 B3.3-182 B3.5-12 B3.6-111 B3.3-26 B3.3-183 83.5-13 B3.6-118 B3.3-27 B3.3-184 B3.5-14 B3.6-119 B3.3-27a 83.3-185 B3.5-14a B3.6-121 B3.3-28 63.3-194 B3.5-20 B3.6-124 B3.3-29 B3.3-195 B3.5-20a B3.6-127 B3.3-30 B3.3-196 B3.5-24 83.6-131 B3.3-36 B3.3-205 B3.5-25 B3.6-132 B3.3-37 B3.3-206 83.5-26 83.7-6 B3.3-38 B3.3-207 B3.6-14 83.7-7 63.3-39f B3.3-212 B3.6-22b B3.7-8 B3.3-39g B3.3-213a B3.6-26 B3.7-9 B3.3-39h B3.3-213b 13.6-28a 83.7-10

Attachment 1 to U-604075 Revision 14 Bases Page Listing B3.7-11 B3.8-14 B3.8-87 B3.7-12 B3.8-15 B3.8-92 Bases Rev. 14-3 63.7-13 B3.8-16 B3.8-96 TOC vi B3.7-14 B3.8-17 B3.8-97 B3.7-32 B3.7-15 B3.8-18 B3.9-4 B3.7-33 B3.7-16 B3.8-19 B3.9-7 B3.7-34 B3.7-17 B3.8-19b B3.9-8 B3.7-35 B3.7-18 B3.8-21 B3.9-11 B3.7-36 B3.7-19 B3.8-22 B3.9-18 83.7-37 B3.7-20 B3.8-23 B3.9-21 83.7-38 B3.7-21 B3.8-24 B3.9-24 Bases Rev. 14-4 83.7-22 B3.8-25 B3.9-28 B3.8-18 B3.7-23 13.8-26 B3.9-32 83.8-21 83.7-24 B3.8-28 B3.10-9 83.8-22 B3.7-25 83.8-29 83.10-10 B3.8-27 B3.7-26 83.8-30 83.10-11 83.8-30 B3.7-27 B3.8-31 B3.10-14 B3.8-42 13.7-28 83.8-32 83.10-15 B3.8-43 83.7-29 B3.8-45 13.10-20 B3.8-44 B3.7-30 B3.8-47 B3.10-25 B3.8-45 B3.7-31 B3.8-48 B3.10-38 83.8-48 83.7-32 B3.8-56 B3.10-37 Bases Rev. 14-5 83.7-33 83.8-57 83.10-38 83.1-9 B3.7-34 B3.8-68 B3.10-41 B3.1-10 83.7-35 B3.8-68a 83.1-11 B3.7-36 B3.8-68b B3.1-12 B3.7-37 B3.8-73 83.3-65 13.8-13b B3.8-77

Attachment 2 to U-604075 Revision 14 Bases Rev 14-1 Pages

RHR Shutdown Cooling System-Hot Shutdown B 3.4.9 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.9 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

< 200°F. This decay heat removal is in preparation for performing refueling or maintenance operations, or for keeping the reactor in the Hot Shutdown condition.

The two redundant, manually controlled shutdown cooling subsystems of the RHR System provide decay heat removal.

Each loop consists of a motor driven pump, one heat exchanger, and associated piping and valves. Both loops have a common suction from the same recirculation loop.

Each pump discharges the reactor coolant, after circulation through the respective heat exchanger, to the reactor via separate feedwater lines or to the reactor via the LPCI injection path. The RHR heat exchangers transfer heat to the Shutdown Service Water System (LCO 3.7.1, Division 1 and 2 "[Shutdown Service Water (SX)] Subsystem and Ultimate Heat Sink (UHS)").

APPLICABLE Decay heat removal by the RHR System in the shutdown cooling SAFETY ANALYSES mode is not required for mitigation of any event or accident evaluated in the safety analyses. Decay heat removal is, however, an important safety function that must be accomplished or core damage could result. The RHR shutdown cooling mode is not credited as safety related decay heat removal, since it is not single failure proof due to the common suction. The alternate shutdown cooling mode using LPCI and SRV's is credited for safety related decay heat removal and is single failure proof. However, the RHR System in the shutdown cooling mode is a significant contributor to risk reduction. Therefore, the RHR Shutdown Cooling System, with its common suction from Reactor Recirculation, is retained as a Technical Specification.

LCO Two RHR shutdown cooling subsystems are required to be OPERABLE, and, when no recirculation pump is in operation, one shutdown cooling subsystem must be in operation. An OPERABLE RHR shutdown cooling subsystem consists of one OPERABLE RHR pump, one heat exchanger, and the associated piping and valves. Each shutdown cooling subsystem is considered OPERABLE if it can be manually aligned (remote (continued)

CLINTON B 3.4-43 Revision No. 14-1

RHR Shutdown Cooling System-Cold Shutdown B 3.4.10 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.10 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 at

200 0 F. This decay heat removal is in preparation for performing refueling or maintenance operations, or for keeping the reactor in the Cold Shutdown condition.

The two redundant, manually controlled shutdown cooling subsystems of the RHR System provide decay heat removal.

Each loop consists of a motor driven pump, one heat exchanger, and associated piping and valves. Both loops have a common suction from the same recirculation loop.

Each pump discharges the reactor coolant, after circulation through the respective heat exchanger, to the reactor via separate feedwater lines or to the reactor via the LPCI injection path.

APPLICABLE Decay heat removal by the RHR System in the shutdown cooling SAFETY ANALYSES mode is not required for mitigation of any event or accident evaluated in the safety analyses. Decay heat removal is, however, an important safety function that must be accomplished or core damage could result. The RHR shutdown cooling mode is not credited as safety related decay heat removal, since it is not single failure proof due to the common suction. The alternate shutdown cooling mode using LPCI and SRV's is credited for safety related decay heat removal and is single failure proof. However, the RHR System in the shutdown cooling mode is a significant contributor to risk reduction. Therefore, the RHR Shutdown Cooling System is retained as a Technical Specification.

LCO Two RHR shutdown cooling subsystems are required to be OPERABLE, and, when no recirculation pump is in operation, one shutdown cooling subsystem must be in operation. An OPERABLE RHR shutdown cooling subsystem consists of one OPERABLE RHR pump, one heat exchanger, and the associated piping and valves. Each shutdown cooling subsystem is considered OPERABLE if it can be manually aligned (remote or (continued)

CLINTON B 3.4-48 Revision No. 14-1

ECCS--Operating B 3.5.1 BASES (continued)

REFERENCES 1. USAR, Section 6.3.2.2.3.

2. USAR, Section 6.3.2.2.4.

3. USAR, Section 6.3.2.2.1.

4. USAR, Section 6.3.2.2.2.

5. USAR, Section 15.2.8.

6. USAR, Section 15.6.4.

7. USAR, Section 15.6.5.

8. 10 CFR 50, Appendix K.

9. USAR, Section 6.3.3.

10. 10 CFR 50.46.

11. USAR, Section 6.3.3.3.

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

(NRC), "Recommended Interim Revisions to LCO's for ECCS Components," December 1, 1975.

13 NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.

14. USAR, Table 6.3-8.

15. USAR, Section 7.3.1.1.1.4.

16. NEDO-32291-A, "System Analyses for Elimination of Selected Response Time Testing Requirements," January 1994.

17. Calculation IP-0-0044.

18. Calculations 01HP09/10/II/15, IP-C-0042.

19. Calculations OlLP08/II/14/16, IP-C-0043.

20. Calculations 01RH19/20/22/26, IP-C-0041.

21. Calculation IP-0-0024.

22. ASME/ANSI OM-1987, Operation and Maintenance of Nuclear Power Plants, Part 1.

23. ASME Code for Operation and Maintenance of Nuclear Power Plants.

24. NEDC-32945P, "Clinton Power Station SAFER/GESTR-LOCA Analysis," June 2000.

CLINTON B 3.5-14b Revision No. 14-1

ECCS-- Shutdown B 3.5.2 BASES SURVEILLANCE SR 3.5.2.4 (continued)

REQUIREMENTS 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 operate in the shutdown cooling mode to remove decay heat and sensible heat from the reactor. Therefore, RHR valves that are required for LPCI subsystem operation may be aligned for decay heat removal.

This SR is modified by a Note that allows one LPCI subsystem of the RHR System to be considered OPERABLE for the ECCS function if all the required valves in the LPCI flow path can be manually realigned (remote or local) to allow injection into the RPV and the system is not otherwise inoperable. This will ensure adequate core cooling if an inadvertent vessel draindown should occur.

REFERENCES 1. USAR, Section 6.3.3.

2. Calculation IP-0-0049.

3. Calculations OIHP09/10/11 and IP-C-0042.

4. Calculations 0lLP08/11/14 and IP-C-0043.

5. Calculations 01RH19/20/22/26 and IP-C-0041.

CLINTON B 3.5-20a Revision No. 14-1

RHR Suppression Pool Cooling B 3.6.2.3 BASES SURVEILLANCE SR 3.6.2.3.2 REQUIREMENTS (continued) Verifying each RHR pump develops a flow rate Ž 4550 gpm, with flow through the associated heat exchanger to the suppression pool, ensures that pump performance has not degraded during the cycle. Flow is a normal test of centrifugal pump performance required by ASME (Ref. 3).

This test confirms one point on the pump design curve, and the results are indicative of overall performance. Such inservice inspections 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.

With regard to RHR pump flow rate values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value with respect to instrument uncertainties. This requires additional margin to be added to the limit to compensate for instrument uncertainties for implementation in the associated plant procedures. (Ref. 5).

REFERENCES 1. USAR, Section 6.2.

2. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.

3. ASME Code for Operation and Maintenance of Nuclear Power Plants.

4. USAR, Section 5.4.7.

5. Calculations 01RH20/22/25 and IP-C-0041.

CLINTON B 3. 6-58b Revision No. 14-1

RHR-High Water Level B 3.9.8 B 3.9 REFUELING OPERATIONS B 3.9.8 Residual Heat Removal (RHR)-High Water Level BASES BACKGROUND The purpose of the RHR System in MODE 5 is to remove decay heat and sensible heat from the reactor coolant, as required by GDC 34. Each of the two shutdown cooling loops of the RHR System can provide the required decay heat removal.

However, the shutdown cooling loops are single failure proof per GDC 34 only with Alternate Shutdown Cooling. Each loop consists of one motor driven pump, a heat exchanger, and associated piping and valves. Both loops have a common suction from the same recirculation loop. Each pump discharges the reactor coolant, after it has been cooled by circulation through the respective heat exchanger, to the reactor via separate feedwater lines or to the upper containment pool via a common single flow distribution sparger, or to the reactor via the low pressure coolant injection path. The RHR heat exchangers transfer heat to the Shutdown Service Water System. The RHR shutdown cooling mode is manually controlled.

In addition to the above RHR subsystems, the volume of water above the reactor pressure vessel (RPV) flange provides a heat sink for decay heat removal.

APPLICABLE With the unit in MODE 5, the RHR shutdown cooling subsystem SAFETY ANALYSES is not required to mitigate any events or accidents evaluated in the safety analyses. The RHR System is required for removing decay heat to maintain the temperature of the reactor

,coolant.

Although the RHR shutdown cooling subsystem does not meet a specific criterion of the NRC Policy Statement, it was identified in the NRC Policy Statement as an important contributor to risk reduction. Therefore, the RHR shutdown cooling subsystem, with its common suction from reactor recirculation, is retained as a Specification.

LCO Only one RHR shutdown cooling subsystem is required to be OPERABLE in MODE 5 with irradiated fuel in the RPV and with the water level Ž 22 ft 8 inches above the RPV flange. Only one subsystem is required because the volume of water above the RPV flange provides backup decay heat removal capability.

(continued)

CLINTON B 3. 9-25 Revision No. 14-1

RHR-Low Water Level B 3.9.9 B 3.9 REFUELING OPERATIONS B 3.9.9 Residual Heat Removal (RHR)--Low Water Level BASES BACKGROUND The purpose of the RHR System in MODE 5 is to remove decay heat and sensible heat from the reactor coolant, as required by GDC 34. Each of the two shutdown cooling loops of the RHR System can provide the required decay heat removal.

However, the shutdown cooling loops are single failure proof per GDC 34 only with Alternate Shutdown Cooling. Each loop consists of one motor driven pump, a heat exchanger, and associated piping and valves. Both loops have a common suction from the same recirculation loop. Each pump discharges the reactor coolant, after it has been cooled by circulation through the respective heat exchanger, to the reactor via separate feedwater lines, to the upper containment pool via a common single flow distribution sparger, or to the reactor via the low pressure coolant injection path. The RHR heat exchangers transfer heat to the Shutdown Service Water System. The RHR shutdown cooling mode is manually controlled.

APPLICABLE With the unit in MODE 5, the RHR shutdown cooling subsystem SAFETY ANALYSES is not required to mitigate any events or accidents evaluated in the safety analyses. The RHR System is required for removing decay heat to maintain the temperature of the reactor coolant.

Although the RHR shutdown cooling subsystem does not meet a specific criterion of the NRC Policy Statement, it was identified in the NRC Policy Statement as an important contributor to risk reduction. Therefore, the RHR shutdown cooling subsystem, with its common suction from reactor recirculation, is retained as a Specification.

LCO In MODE 5 with irradiated fuel in the reactor pressure vessel (RPV) and with the water level < 22 ft 8 inches above the RPV flange both RHR shutdown cooling subsystems must be OPERABLE.

An OPERABLE RHR shutdown cooling subsystem consists of an RHR pump, a heat exchanger, valves, piping, instruments, and controls to ensure an OPERABLE flow path.

(continued)

CLINTON B 3.9-29 Revision No. 14-1

Attachment 2 to U-604075 Revision 14 Bases Rev 14-2 Pages

TABLE OF CONTENTS B 3.4 REACTOR COOLANT SYSTEM (RCS) (continued)

B 3.4.3 Jet Pump s ............................................................................................................. B 3.4-13 B 3.4.4 Safety/Relief Valves (S/RVs) .............................................................................. B 3.4-17 B 3.4.5 RCS Operational LEAKAGE .............................................................................. B 3.4-23 B 3.4.6 RCS Pressure Isolation Valve (PIV) Leakage ..................................................... B 3.4-28 B 3.4.7 RCS Leakage Detection Instrumentation .......................... B 3.4-33 B 3.4.8 RCS Specific Activity ......................................................................................... B 3.4-39 B 3.4.9 Residual Heat Removal (RHR) Shutdown Cooling System - Hot Shutdown ............................................................................... B 3.4-43 B 3.4.10 Residual Heat Removal (RHR) Shutdown Cooling System - Cold Shutdown ............................................................................. B 3.4-48 B 3.4.11 RCS Pressure and Temperature (P/T) Limits ...................................................... B 3.4-53 B 3.4.12 Reactor Steam Dome Pressure ............................................................................ B 3.4-63 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM ................................................................ 3.5-1 3.5.1 EC C S - Operating ................................................................................................ 3.5-1 3.5.2 E C C S - Shutdow n ................................................................................................ 3.5-6 3.5.3 RC IC System ....................................................................................................... 3.5-10 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM ..................................................... B 3.5-1 B 3.5.1 E C C S - Operating ................................................................................................ B 3.5-1 B 3.5.2 EC C S - Shutdow n ................................................................................................ B 3.5-15 B 3.5.3 R C IC System ....................................................................................................... B 3.5-2 1 3.6 CONTAINMENT SYSTEMS ...................................................................................... 3.6-1 3.6.1.1 Prim ary C ontainm ent ........................................................................................... 3.6-1 3.6.1.2 Primary Containment Air Locks .......................................................................... 3.6-3 3.6.1.3 Primary Containment Isolation Valves (PCIVs) ................................................. 3.6-9 3.6.1.4 Primary Containment Pressure ............................................................................ 3.6-20 3.6.1.5 Primary Containment Air Temperature ............................................................... 3.6-21 3.6.1.6 Low-Low Set (LLS) Valves ................................................................................ 3.6-22 3.6.1.7 Residual Heat Removal (RHR) Containment Spray System ............................... 3.6-24 3 .6.1.8 D eleted .............................................................................................................. 3 .6-26 3.6.1.9 Feedwater Leakage Control System (FWLCS) ................................................... 3.6-27a 3.6.2.1 Suppression Pool Average Temperature ............................................................. 3.6-28 3.6.2.2 Suppression Pool Water Level ............................................................................ 3.6-31 3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling ................................. 3.6-32 3.6.2.4 Suppression Pool Makeup (SPMU) System ........................................................ 3.6-34 3 .6 .3.1 Deleted ............................................................................................................... 3 .6-36 3.6.3.2 Primary Containment and Drywell Hydrogen Igniters ........................................ 3.6-38 (continued)

CLINTON Revision No. 14-2 iv

TABLE OF CONTENTS 3.6 CONTAINMENT SYSTEMS (continued) 3.6.3.3 Containment/Drywell Hydrogen Mixing Systems .............................................. 3.6-41 3.6.4.1 Secondary Containment ....................................................................................... 3.6-43 3.6.4.2 Secondary Containment Isolation Dampers (SCIDs) .......................................... 3.6-47 3.6.4.3 Standby Gas Treatment (SGT) System ............................................................... 3.6-51 3.6 .5.1 D ryw ell ............................................................................................................... 3 .6-54 3.6.5.2 D ryw ell A ir Lock ................................................................................................. 3.6-56 3.6.5.3 D ryw ell Isolation V alves ..................................................................................... 3.6-61 3.6.5.4 Drywell Pressure ................................................................... 3.6-66 3.6.5.5 Drywell Air Temperature .................................... 3.6-67 3.6.5.6 Drywell Post - LOCA Vacuum Relief System ..................................................... 3.6-68 B 3.6 CONTAINMENT SYSTEMS ...................................................................................... B 3.6-1 B 3.6.1.1 Prim ary C ontainm ent ................................................................................................... B 3.6-1 B 3.6.1.2 Primary Containment Air Locks .................................................................................. B 3.6-6 B 3.6.1.3 Primary Containm ent Isolation Valves (PCIVs) .......................................................... B 3.6-15 B 3.6.1.4 Primary Containment Pressure ..................................................................................... B 3.6-29 B 3.6.1.5 Primary Containment Air Temperature ........................................................................ B 3.6-32 B 3.6.1.6 Low-Low Set (LLS) Valves ......................................................................................... B 3.6-35 B 3.6.1.7 Residual Heat Removal (RHR) Containment Spray System ....................................... B 3.6-39 B 3.6.1.8 D eleted ................................................. .. ....................... B 3.6-44 B 3.6.1.9 Feedwater Leakage Control System (FWLCS) ........................................................... B 3.6-45 B 3.6.2.1 Suppression Pool Average Temperature ...................................................................... B 3.6-48 B 3.6.2.2 Suppression Pool Water Level ..................................................................................... B 3.6-53 B 3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling ......................................... B 3.6-56 B 3.6.2.4 Suppression Pool Makeup (SPMU) System ................................................................. B 3.6-60 B 3 .6.3.1 Deleted ........................................................................................... B 3 .6-66 B 3.6.3.2 Primary Containment and Drywell Hydrogen Igniters ................................... B 3.6-72 B 3.6.3.3 Containment/Drywell Hydrogen Mixing System ......................................................... B 3.6-78 B 3.6.4.1 Secondary Containment ............................................................................................... B 3.6-83 B 3.6.4.2 Secondary Containm ent Isolation Dampers (SCIDs) ................................................... B 3.6-89 B 3.6.4.3 Standby Gas Treatment (SGT) System ........................................................................ B 3.6-96 B 3 .6.5.1 D ryw ell ........................................................................................................................ B 3.6-102 B 3.6.5.2 D ryw ell A ir L ock ......................................................................................................... B 3.6-106 B 3.6.5.3 Drywell Isolation Valves .............................................................................................. B 3.6-113 B 3.6.5.4 D rywell Pressure .......................................................................................................... B 3.6-122 B 3.6.5.5 Drywell Air Temperature ............................................................................................. B 3.6-125 B 3.6.5.6 Drywell Post-LOCA Vacuum Relief System ............................................................... B 3.6-128 (continued)

CLINTON Revision No. 14-2 v

TABLE OF CONTENTS (continued) 3.7 PLANT SYSTEMS ......................... ................. 3.7-1 3.7.1 Division 1 and 2 Shutdown Service Water (SX) Subsystems and Ultimate Heat Sink (UHS) ................................................................... 3.7-1 3.7.2 Division 3 Shutdown Service Water (SX)

Sub sy stem ................................................................................................... 3.7-3 3.7.3 Control Room Ventilation System ...................................................................... 3.7-4 3.7.4 Control Room Air Conditioning (AC) System .................................................... 3.7-8 3.7.5 Main Condenser Offgas ....................................................................................... 3.7-11 3.7.6 Main Turbine Bypass System .............................................................................. 3.7-13 3.7.7 Fuel Pool W ater Level ......................................................................................... 3.7-14 B 3.7 PLANT SYSTEMS ...................................................................................................... B 3.7-1 B 3.7.1 Division I and 2 Shutdown Service Water (SX)

Subsystems and Ultimate Heat Sink (UHS) ............................................... B 3.7-1 B 3.7.2 Division 3 Shutdown Service W ater Subsystem (SX) ........................................ B 3.7-8 B 3.7.3 Control Room Ventilation System ...................................................................... B 3.7-11 B 3.7.4 Control Room Air Conditioning (AC) System .................................................... B 3.7-22 B 3.7.5 Main Condenser Offgas ....................................................................................... B 3.7-28 B 3.7.6 Main Turbine Bypass System .............................................................................. B 3.7-32 B 3.7.7 Fuel Pool W ater Level ......................................................................................... B 3.7-35 3.8 ELECTRICAL POW ER SYSTEMS ............................................................................ 3.8-1 3.8.1 AC Sources - Operating ....................................................................................... 3.8-1 3.8.2 AC Sources - Shutdown ....................................................................................... 3.8-16 3.8.3 Diesel Fuel Oil, Lube Oil, and Starting Air ........................................................ 3.8-20 3.8.4 DC Sources - Operating ....................................................................................... 3.8-24 3.8.5 DC Sources - Shutdown ....................................................................................... 3.8-27 3.8.6 Battery Cell Parameters ....................................................................................... 3.8-30 3.8.7 Inverters - Operating ............................................................................................ 3.8-34 3.8.8 Inverters - Shutdown ............................................................................................ 3.8-36 3.8.9 Distribution Systems - Operating ......................................................................... 3.8-39 3.8.10 Distribution Systems - Shutdown ......................................................................... 3.8-42 3.8.11 Static VAR Compensator (SVC) Protection Systems ......................................... 3.8-44 B 3.8 ELECTRICAL POWER SYSTEMS ............................................................................ B 3.8-1 B 3.8.1 AC Sources- Operating ....................................................................................... B 3.8-1 B 3.8.2 AC Sources - Shutdown ....................................................................................... B 3.8-33 B 3.8.3 Diesel Fuel Oil, Lube Oil, and Starting Air ....................................................... B 3.8-40 B 3.8.4 DC Sources- Operating ....................................................................................... B 3.8-49 B 3.8.5 DC Sources- Shutdown ....................................................................................... B 3.8-59 B 3.8.6 Battery Cell Parameters ....................................................................................... B 3.8-64 B 3.8.7 Inverters - Operating ............................................................................................ B 3.8-69 B 3.8.8 Inverters - Shutdown ............................................................................................ B 3.8-74 B 3.8.9 Distribution Systems - Operating ......................................................................... B 3.8-78 B 3.8.10 Distribution Systems - Shutdown ......................................................................... B 3.8-89 B 3.8-11 Static VAR Compensator (SVC) Protection Systems ......................................... B 3.8-93 (continued)

CLINTON Revision No. 14-2 vi

Control Rod OPERABILITY B 3.1.3 BASES (continued)

SURVEILLANCE SR 3.1.3.1 REQUIREMENTS The position of each control rod must be determined, to ensure adequate information on control rod position is available to the operator for determining control rod OPERABILITY and controlling rod patterns. Control rod position may be determined by the use of OPERABLE position indicators, by moving control rods to a position with an OPERABLE indicator, or by the use of other appropriate methods. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.1.3.2 Deleted SR 3.1.3.3 Control rod insertion capability is demonstrated by inserting each partially or fully withdrawn control rod at least one notch and observing that the control rod moves.

The control rod may then be returned to its original position. This ensures the control rod is not stuck and is free to insert on a scram signal. This Surveillance is modified by a note identifying that the Surveillance is not required to be performed when THERMAL POWER is less than or equal to the actual LPSP of the RPCS since the notch insertions may not be compatible with the requirements of BPWS (LCO 3.1.6) and the RPCS (LCO 3.3.2.1). This note also provides a time allowance (i.e., the associated SR Frequency plus the extension allowed by SR 3.0.2) such that the Surveillance is not required to be performed until the next scheduled control rod testing. This note provides this allowance to prevent unnecessary perturbations in reactor operation to perform this testing on a control rod. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. At any time, if a control rod is (continued)

CLINTON B 3.1-19 Revision No. 14-2

Control Rod Scram Times B 3.1.4 BASES SURVEILLANCE SR 3.1.4.2 REQUIREMENTS Additional testing of a sample of control rods is required to verify the continued performance of the scram function during the cycle. A representative sample contains at least 10% of the control rods. The sample remains "representative" if no more than 7.5% of the control rods in the tested sample are determined to be "slow." If more than 7.5% of the sample is declared to be "slow" per the criteria in Table 3.1.4-1, additional control rods are tested until this 7.5% criterion (i.e., 7.5% of the entire sample size) is satisfied, or until the total number of "slow" control rods throughout the core, from all surveillances) exceed the LCO limit. For planned testing, the control rods selected for the sample should be different for each test. Data from inadvertent scrams should be used whenever possible to avoid unnecessary testing at power, even if the control rods with data were previously tested in a sample. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to scram time values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 8).

SR 3.1.4.3 When work that could affect the scram insertion time is performed on a control rod or the CRD System, testing must be done to demonstrate that each affected control rod retains adequate scram performance over the range of applicable reactor pressures from zero to the maximum permissible pressure. The scram testing must be performed once before declaring the control rod OPERABLE. The required scram time testing must demonstrate that the affected control rod is still within acceptable limits by demonstrating an acceptable scram insertion time to notch position 13. The scram time acceptance criteria for this alternate test shall be determined by linear interpolation between 0.95 seconds at a reactor coolant pressure of 0 psig and 1.40 seconds at 950 psig. The limits for reactor pressures < 950 psig are established based on a high (continued)

CLINTON B 3.1-26 Revision No. 14-2

Control Rod Scram Accumulators B 3.1.5 BASES ACTIONS D.1 (continued)

The reactor mode switch must be immediately placed in the shutdown position if either Required Action and associated Completion Time associated with the loss of the CRD pump (Required Actions B.1 and C.1) cannot be met. This ensures that all insertable control rods are inserted and that the reactor is in a condition that does not require the active function (i.e., scram) of the control rods. This Required Action is modified by a Note stating that the Required Action is not applicable if all control rods associated with the inoperable scram accumulators are fully inserted, since the function of the control rods has been performed.

SURVEILLANCE SR 3.1.5.1 REQUIREMENTS SR 3.1.5.1 requires that the accumulator pressure be checked periodically to ensure adequate accumulator pressure exists to provide sufficient scram force. The primary indicator of accumulator OPERABILITY is the accumulator pressure. A minimum accumulator pressure is specified, below which the capability of the accumulator to perform its intended function becomes degraded and the accumulator is considered inoperable. The minimum accumulator pressure of 1520 psig is well below the expected pressure of 1750 psig (Ref. 2).

Declaring the accumulator inoperable when the minimum pressure is not maintained ensures that significant degradation in scram times does not occur. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to accumulator pressure values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is not considered to be a nominal value with respect to instrument uncertainties. This requires additional margin to be added to the limit to compensate for instrument uncertainties, for implementation in the associated plant procedures (Ref. 6).

(continued)

CLINTON B 3. 1-32 Revision No. 14-2

Control Rod Pattern B 3.1.6 BASES ACTIONS B.1 and B.2 (continued) withdrawals have. Required Action B.l is modified by a Note that allows the affected control rods to be bypassed in RACS in accordance with SR 3.3.2.1.9 to allow insertion only.

With nine or more OPERABLE control rods not in compliance with BPWS, the reactor mode switch must be placed in the shutdown position within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . With the reactor mode switch in Shutdown, the reactor is shut down, and therefore does not meet the applicability requirements of this LCO.

The allowed Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is reasonable to allow insertion of control rods to restore compliance, and is appropriate relative to the low probability of a CRDA occurring with the control rods out of sequence.

SURVEILLANCE SR 3.1.6.1 REQUIREMENTS The control rod pattern is periodically verified to be in compliance with the BPWS, ensuring the assumptions of the CRDA analyses are met. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

The RPC provides control rod blocks to enforce the required control rod sequence and is required to be OPERABLE when operating at < 16.7% RTP.

REFERENCES 1. USAR, Section 15.0

2. USAR, Section 15.4.9.

3. NUREG-0979, "NRC Safety Evaluation Report Related to the Final Design Approval of the GESSAR II BWR/6 Nuclear Island Design, Docket No. 50-447,"

Section 4.2.1.3.2, April 1983.

4. NUREG-0800, "Standard Review Plan," Section 15.4.9, "Radiological Consequences of Control Rod Drop Accident (BWR)," Revision 2, July 1981.

5. 10 CFR 100.11, "Determination of Exclusion Area, Low Population Zone, and Population Center Distance."

(continued)

CLINTON B 3.1-36 Revision No. 14-2

SLC System B 3.1.7 BASES ACTIONS A.1 (continued) remaining OPERABLE subsystem could result in reduced SLC System shutdown capability. The 7 day Completion Time is based on the availability of an OPERABLE subsystem capable of performing the intended SLC System function and the low probability of a Design Basis Accident (DBA) or severe transient occurring concurrent with the failure of the Control Rod Drive System to shut down the plant.

B.1 If both SLC subsystems are inoperable, at least one subsystem must be restored to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . The allowed Completion Time of 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months is considered acceptable, given the low probability of a DBA or transient occurring concurrent with the failure of the control rods to shut down the reactor.

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 MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 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 3.1.7.1, SR 3.1.7.2, and SR 3.1.7.3 REQUIREMENTS SR 3.1.7.1 through SR 3.1.7.3 verify certain characteristics of the SLC System (i.e., the volume and temperature of the borated solution in the storage tank, and temperature of the pump suction piping), thereby ensuring the SLC System OPERABILITY without disturbing normal plant operation.

These Surveillances ensure the proper borated solution and temperature, including the temperature of the pump suction piping, are maintained. Maintaining a minimum specified borated solution temperature is important in ensuring that the boron remains in solution and does not precipitate out (continued)

CLINTON B 3.1-40 Revision No. 14-2

SLC System B 3.1.7 BASES SURVEILLANCE SR 3.1.7.1, SR 3.1.7.2, and SR 3.1.7.3 (continued)

REQUIREMENTS in the storage tank or in the pump suction piping. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to volume and temperature values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Refs. 3, 4, 5).

SR 3.1.7.4 and SR 3.1.7.6 SR 3.1.7.4 verifies the continuity of the explosive charges in the injection valves to ensure proper operation will occur if required. Other administrative controls, such as those that limit the shelf life of the explosive charges, must be followed. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.1.7.6 verifies each valve in the system is in its correct position, but does not apply to the squib (i.e.,

explosive) valves. Verifying the correct alignment for manual, power operated, and automatic valves in the SLC System flow path ensures that the proper flow paths will exist for system operation. A valve is also allowed to be in the nonaccident position, provided it can be aligned to the accident position from the control room. This is acceptable since the SLC System is a manually initiated system. This Surveillance does not apply to valves that are locked, sealed, or otherwise secured in position, since they were verified to be in the correct position prior to locking, sealing, or securing. This verification of valve alignment 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 positions. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3. 1-41 Revision No. 14-2

SLC System B 3.1.7 BASES SURVEILLANCE SR 3.1.7.5 REQUIREMENTS (continued) This Surveillance requires an examination of the sodium pentaborate solution by using chemical analysis to ensure the proper concentration of boron exists in the storage tank. SR 3.1.7.5 must be performed anytime boron or water is added to the storage tank solution to establish that the boron solution concentration is within the specified limits.

This Surveillance must be performed anytime the solution temperature is restored to > 70°F, to ensure no significant boron precipitation occurred. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to boron concentration values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 6).

SR 3.1.7.7 Demonstrating each SLC System pump develops a flow rate

> 41.2 gpm at a discharge pressure > 1220 psig ensures that pump performance has not degraded during the fuel cycle.

This minimum pump flow rate requirement ensures that, when combined with the sodium pentaborate solution concentration requirements, the rate of negative reactivity insertion from the SLC System will adequately compensate for the positive reactivity effects encountered during power reduction, cooldown of the moderator, and xenon decay. This test confirms one point on the pump design curve, and is indicative of overall performance. Such inservice inspections confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance. The Frequency of this Surveillance is in accordance with the Inservice Testing Program.

Values obtained for flow rate and discharge pressure pursuant to this SR, as read from plant indication instrumentation, are considered to be nominal values and therefore do not require compensation for instrument indication uncertainties (Ref. 7).

(continued)

CLINTON B 3.1-42 Revision No. 14-2

SLC System B 3.1.7 BASES SURVEILLANCE SR 3.1.7.8 and SR .3.1.7.9 REQUIREMENTS (continued) These Surveillances ensure that there is a functioning flow path from the boron solution storage tank to the RPV, including the firing of an explosive valve. The replacement charge for the explosive valve shall be from the same manufactured batch as the one fired or from another batch that has been certified by having one of that batch successfully fired.

The Surveillance may be performed in separate steps to prevent injecting boron into the RPV. An acceptable method for verifying flow from the pump to the RPV is to pump demineralized water from a test tank through one SLC subsystem and into the RPV.

Demonstrating that all piping between the boron solution storage tank and the suction inlet to the injection pumps is unblocked ensures that there is a functioning flow path for injecting the sodium pentaborate solution. An acceptable method for verifying that the suction piping is unblocked is to pump from the storage tank to the test tank. Following this test, the piping will be drained and flushed with demineralized water. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

If in performing SR 3.1.7.3, it is determined that the temperature of this piping has fallen below the specified minimum, SR 3.1.7.9 must be performed once within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after the piping temperature is restored to > 70°F.

REFERENCES 1. 10 CFR 50.62.

2. USAR, Section 9.3.5.3.

3. Calculation IP-0-0012.

4. Calculation IP-0-0013.

5. Calculation IP-0-0014.

6. Calculation IP-0-0015.

7. Calculation IP-0-0016.

8. NUREG-1465, "Accident Source Terms for Light-Water Nuclear Power Plants, Final Report," February 1, 1995.

9. 10 CFR 50.67, "Accident Source Terms."

CLINTON B 3.1-43 Revision No. 14-2

SDV Vent and Drain Valves B 3.1.8 BASES (continued)

SURVEILLANCE SR 3.1.8.1 REQUIREMENTS During normal operation, the SDV vent and drain valves should be in the open position (except when performing SR 3.1.8.2) to allow for drainage of the SDV piping.

Verifying that each valve is in the open position ensures that the SDV vent and drain valves will perform their intended function during normal operation. This SR does not require any testing or valve manipulation; rather, it involves verification that the valves are in the correct position. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. Improper valve position (closed) would not affect the isolation function.

SR 3.1.8.2 During a scram, the SDV vent and drain valves should close to contain the reactor water discharged to the SDV piping.

Cycling each valve through its complete range of motion (closed and open) ensures that the valve will function properly during a scram. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.1.8.3 SR 3.1.8.3 is an integrated test of the SDV vent and drain valves to verify total system performance. After receipt of a simulated or actual scram signal, the closure of the SDV vent and drain valves is verified. The closure time of 30 seconds after a receipt of a scram signal is based on the bounding leakage case evaluated in the accident analysis.

Similarly, after receipt of a simulated or actual scram reset signal, the opening of the SDV vent and drain valves is verified. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.1.1 and the scram time testing of control rods in LCO 3.1.3, "Control Rod OPERABILITY," overlap this Surveillance to provide complete testing of the assumed safety function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to SDV vent and drain valve closing time values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 4).

(continued)

CLINTON B 3.1-47 Revision No. 14-2

SDV Vent and Drain Valves B 3.1.8 BASES (continued)

REFERENCES 1. USAR, Section 4.6.1.1.2.4.2.5.

2. 10 CFR 100.

3. NUREG-0803, "Generic Safety Evaluation Report Regarding Integrity of BWR Scram System Piping,"

August 1981.

4. Calculation IP-0-0017.

CLINTON B 3.1-48 Revision No. 14-2

APLHGR B 3.2.1 BASES ACTIONS B.l (continued)

POWER must be reduced to < 21.6% RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to < 21.6% RTP in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.2.1.1 REQUIREMENTS APLHGRs are required to be initially calculated within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL POWER is Ž 21.6% RTP and then periodically thereafter. They are compared to the specified limits in the COLR to ensure that the reactor is operating within the assumptions of the safety analysis. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance after THERMAL POWER Ž 21.6% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to APLHGR values obtained pursuant to this SR, as determined from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 6).

(continued)

CLINTON B 3.2-4 Revision No. 14-2

MCPR B 3.2.2 BASES SURVEILLANCE SR 3.2.2.1 REQUIREMENTS The MCPR is required to be initially calculated within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL POWER is Ž 21.6% RTP and periodically thereafter. It is compared to the specified limits in the COLR to ensure that the reactor is operating within the assumptions of the safety analysis. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance after THERMAL POWER reaches Ž 21.6% RTP is acceptable given the large inherent margin to operating limits at low power levels. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to MCPR values obtained pursuant to this SR, as determined from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 9).

SR 3.2.2.2 Because the transient analyses may take credit for conservatism in the control rod scram speed performance, it must be demonstrated that the specific scram speed distribution is consistent with that used in the transient analyses. SR 3.2.2.2 determines the actual scram speed distribution and compares it with the assumed distribution.

The MCPR operating limit is then determined based either on the applicable limit associated with scram times of LCO 3.1.4, '"Control Rod Scram Times," or the realistic scram times. The scram time dependent MCPR limits are contained in the COLR. This determination must be preformed and any necessary changes must be implemented with in 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months after each set of control rod scram time tests required by SR 3.1.4.1, SR 3.1.4,2, and SR 3.1.4.4 because the effective scram speed distribution may change during the cycle or after maintenance that could affect scram times. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is acceptable due to the relatively minor changes in the actual control rod scram speed distribution expected during the fuel cycle.

(continued)

CLINTON B 3.2-8 Revision No. 14-2

LHGR B 3.2.3 BASES LCO With only one recirculation loop in operation, in (continued) conformance with the requirements of LCO 3.4.1, "Recirculation Loops Operating," the limit is determined by multiplying the exposure dependent LHGR limit by the smaller of either LHGRFACf, LHGRFACP, and the LHGR single loop operation multiplier, where the single loop operation multiplier has been determined by a specific single recirculation loop analysis (Refs. 6 and 7).

APPLICABILITY The LHGR limits are derived from fuel design analysis that is limiting at high power level conditions. At core thermal power levels < 21.6% RTP, the reactor is operating with a substantial margin to the LHGR limits and, therefore, the Specification is only required when the reactor is operating at > 21.6% RTP.

ACTIONS A.1 If any LHGR exceeds its required limit, an assumption regarding an initial condition of the fuel design analysis is not met. Therefore, prompt action should be taken to restore the LHGR(s) to within its required limit(s) such that the plant is operating within analyzed conditions and within the design limits of the fuel rods. The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is normally sufficient to restore the LHGR(s) to within its limit and is acceptable based on the low probability of a transient occurring simultaneously with the LHGR out of specification.

B.1 If the LHGR cannot be restored to within its required limit within the associated Completion Time, the plant must be brought to a MODE or other specified condition in which the LCO does not apply. To achieve this status, THERMAL POWER must be reduced to < 21.6% RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to < 21.6% RTP in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.2.3.1 REQUIREMENTS The LHGRs are required to be initially calculated within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL POWER is > 21.6% RTP and periodically thereafter. They are compared with the specified limits in the COLR to ensure that the reactor is operating within the assumptions of the safety analysis. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance after THERMAL POWER

>_ 21.6% RTP is achieved is acceptable given the large inherent margin to operating limits at lower power levels.

(continued)

CLINTON B 3-2-11 Revision No. 14-2

RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does REQUIREMENTS not significantly reduce the probability that the RPS will (continued) trip when necessary.

SR 3.3.1.1.1 Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value.

Significant deviations between the instrument channels could be an indication of excessive instrument drift on one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.

SR 3.3.1.1.2 To ensure that the APRMs are accurately indicating the true core average power, the APRMs are calibrated to the reactor power calculated from a heat balance. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

A restriction to satisfying this SR when < 21.6% RTP is provided that requires the SR to be met only at > 21.6% RTP because it is difficult to accurately maintain APRM indication of core THERMAL POWER consistent with a heat balance when < 21.6% RTP. At low power levels, a high degree (continued)

CLINTON B 3.3-23 Revision No. 14-2

RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.2 (continued)

REQUIREMENTS of accuracy is unnecessary because of the large inherent margin to thermal limits (MCPR and APLHGR) . At > 21.6% RTP, the Surveillance is required to have been satisfactorily performed in accordance with SR 3.0.2. A Note is provided which allows an increase in THERMAL POWER above 21.6% if the Frequency is not met per SR 3.0.2. In this event, the SR must be performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reaching or exceeding 21.6% RTP. Twelve hours is based on operating experience and in consideration of providing a reasonable time in which to complete the SR.

With regard to core thermal power values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 11).

SR 3.3.1.1.3 The Average Power Range Monitor Flow Biased Simulated Thermal Power-High Function uses the recirculation loop drive flows to vary the trip setpoint. This SR ensures that the APRM Function accurately reflects the required setpoint as a function of flow.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.1.4 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. 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.

Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

As noted, SR 3.3.1.1.4 is not required to be performed when entering MODE 2 from MODE 1 since testing of the MODE 2 required IRM and APRM Functions cannot be performed in MODE 1 without utilizing jumpers, lifted leads, or movable (continued)

CLINTON B 3.3-24 Revision No. 14-2

RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.4 (continued)

REQUIREMENTS links. This allows entry into MODE 2 if the Frequency is not met per SR 3.0.2. In this event, the SR must be performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after entering MODE 2 from MODE 1.

Twelve hours is based on operating experience and in consideration of providing a reasonable time in which to complete the SR.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.1.5 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended Function. 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 Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.1.6 and SR 3.3.1.1.7 These Surveillances are established to ensure that no gaps in neutron flux indication exist from subcritical to power operation for monitoring core reactivity status.

The overlap between SRMs and IRMs is required to be demonstrated to ensure that reactor power will not be increased into a region without adequate neutron flux indication. This is required prior to withdrawing SRMs from the fully inserted position since indication is being transitioned from the SRMs to the IRMs.

The overlap between IRMs and APRMs is of concern when reducing power into the IRM range. On power increases, the system design will prevent further increases (initiate a rod block) if adequate overlap is not maintained.

Overlap between IRMs and APRMs exists when sufficient IRMs and APRMs concurrently have onscale readings such that the transition between MODE 1 and MODE 2 can be made without either an APRM downscale rod block or an IRM upscale rod (continued)

CLINTON B 3.3-25 Revision No. 14-2

RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.6 and SR 3.3.1.1.7 (continued)

REQUIREMENTS block. Overlap between SRMs and IRMs similarly exists when, prior to withdrawing the SRMs from the fully inserted position, IRMs are above the downscale value of 5 and increasing as neutron flux increases, prior to the SRMs indication reaching their upscale limit.

As noted, SR 3.3.1.1.7 is only required to be met during entry into MODE 2 from MODE 1. That is, after the overlap requirement has been met and indication has transitioned to the IRMs, maintaining overlap is not required (APRMs may be reading downscale once in MODE 2).

If overlap for a group of channels is not demonstrated (e.g., IRM/APRM overlap), the reason for the failure of the Surveillance should be determined and the appropriate channel(s) declared inoperable. Only those appropriate channel(s) that are required in the current MODE or condition should be declared inoperable.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.1.8 LPRM gain settings are determined from the local flux profiles measured by the Traversing Incore Probe (TIP)

System. This establishes the relative local flux profile for appropriate representative input to the APRM System.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.1.9 and SR 3.3.1.1.12 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. 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. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.3-26 Revision No. 14-2

RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.10 REQUIREMENTS (continued) The calibration of analog trip modules provides a check of the actual trip setpoints. The channel must be declared inoperable if the trip setting is discovered to be less conservative than the Allowable Value specified in Table 3.3.1.1-1. If the trip setting is discovered to be less conservative than accounted for in the appropriate setpoint methodology, but is not beyond the Allowable Value, the channel performance is still within the requirements of the plant safety analysis. Under these conditions, the setpoint must be readjusted to be equal to or more conservative than accounted for in the appropriate setpoint methodology.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.1.11 and SR 3.3.1.1.13 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 SR 3.3.1.1.13 calibration for selected Functions is modified by a Note as identified in Table 3.3.1.1-1. This Note, which applies only to those Functions identified in Table 3.3.1.1-1, is divided into three parts. Part 1 of the Note requires evaluation of instrument performance for the condition where the as-found setting for these instrument channels is outside its As-Found Tolerance (AFT) but conservative with respect to the Allowable Value.

(continued)

CLINTON B 3.3-27 Revision No. 14-2

RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.11 and SR 3.3.1.1.13 (continued)

REQUIREMENTS Evaluation of instrument performance will verify that the instrument will continue to behave in accordance with design-basis assumptions. The purpose of the assessment is to ensure confidence in the instrument performance prior to returning the instrument to service. Initial evaluation will be performed by the technician performing the surveillance who will evaluate the instrument's ability to maintain a stable setpoint within the As-Left Tolerance (ALT) . The technician's evaluation will be reviewed by on-shift operations personnel during the approval of the surveillance data. Subsequent to returning the instrument to service, the deviation is entered into the Corrective Action Program. In accordance with procedures, entry into the Corrective Action Program will require review and documentation of the condition for operability by on-shift operations personnel. Additional evaluation and potential corrective actions as necessary will ensure that any as-found setting found outside the AFT is evaluated for long-term operability trends. If the as-found channel setpoint is not conservative with respect to the Allowable Value, the channel shall be declared inoperable. Part 2 of the Note requires that the instrument channel setpoint shall be reset to within the ALT of the Actual Trip Setpoint (ATSP) . The ATSP is equivalent to or more conservative than the Nominal Trip Setpoint (NTSP). The NTSP is the limiting value of the sensed process variable at which a trip may be set in accordance with the methodology documented in the ORM.

Therefore, the NTSP is equivalent to the Limiting Safety System Setting (LSSS) required by 10 CFR 50.36, "'Technical specifications." The Actual Trip Setpoint is also calculated in accordance with the plant-specific setpoint methodology as documented in the CPS ORM and may include additional margin. The ATSP will ensure that sufficient margin to the safety and/or analytical limit is maintained.

If the as-left instrument channel setpoint cannot be returned to within the ALT of the Actual Trip Setpoint, then the channel shall be declared inoperable. Part 3 of the Note indicates that the Nominal Trip Setpoint and the methodology used to determine the Nominal Trip Setpoint, the As-Found Tolerance and the As-Left Tolerance bands are specified in the ORM.

Note 1 states that neutron detectors are excluded from CHANNEL CALIBRATION because of the difficulty of simulating a meaningful signal. Changes in neutron detector sensitivity are compensated for by performing the calorimetric calibration (SR 3.3.1.1.2) and the LPRM calibration against the TIPs (SR 3.3.1.1.8). A second Note is provided that requires the APRM and the IRM SRs to be performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of entering MODE 2 from MODE 1.

(continued)

CLINTON B 3.3-27a Revision No. 14-2

RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.11 and SR 3.3.1.1.13 (continued)

REQUIREMENTS Testing of the MODE 2 APRM and IRM Functions cannot be performed in MODE 1 without utilizing jumpers, lifted leads, or movable links. This Note allows entry into MODE 2 from MODE 1 if the associated Frequency is not met per SR 3.0.2.

Twelve hours is based on operating experience and in consideration of providing a reasonable time in which to complete the SR. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.1.14 The Average Power Range Monitor Flow Biased Simulated Thermal Power-High Function uses an electronic filter circuit to generate a signal, proportional to the core THERMAL POWER from the APRM neutron flux signal. This filter circuit is representative of the fuel heat transfer dynamics that produce the relationship between the neutron flux and the core THERMAL POWER. The filter time constant is specified in the COLR and must be verified to ensure that the channel is accurately reflecting the desired parameter.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to filter time constant values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 11).

SR 3.3.1.1.15 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channel. The functional testing of control rods, in LCO 3.1.3, "Control Rod OPERABILITY," and SDV vent and drain valves, in LCO 3.1.8, "Scram Discharge Volume (SDV) Vent and Drain Valves," overlaps this Surveillance to provide complete testing of the assumed safety function.

The Self Test System may be utilized to perform this testing for those components that it is designed to monitor.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.3-28 Revision No. 14-2

RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.16 REQUIREMENTS (continued) This SR ensures that scrams initiated from the Turbine Stop Valve Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Functions will not be inadvertently bypassed when THERMAL POWER is > 33.3% RTP. This involves calibration of the bypass channels. Adequate margins for the instrument setpoint methodology are incorporated into the actual setpoint.

If any bypass channel setpoint is nonconservative such that the Functions are bypassed at > 33.3% RTP (e.g., due to open main steam line drain(s), main turbine bypass valve(s) or other reasons), then the affected Turbine Stop Valve Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Functions are considered inoperable. Alternatively, the bypass channel can be placed in the conservative condition (nonbypass). If placed in the nonbypass condition, this SR is met and the channel is considered OPERABLE.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.1.17 This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis. The RPS RESPONSE TIME acceptance criteria are included in plant Surveillance procedures.

As noted, neutron detectors are excluded from RPS RESPONSE TIME testing because the principles of detector operation virtually ensure an instantaneous response time. In addition, for Functions 3, 4, and 5, the associated sensors are not required to be response time tested. For these Functions, response time testing for the remaining channel components, including the ATMs, is required. This allowance is supported by Reference 10.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to RPS RESPONSE TIME values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 12).

(continued)

CLINTON B 3.3-29 Revision No. 14-2

RPS Instrumentation B 3.3.1.1 BASES (continued)

REFERENCES 1. USAR, Section 7.2.

2. USAR, Section 5.2.2.

3. USAR, Section 6.3.3.

4. USAR, Chapter 15.

5. USAR, Section 15.4.1.2.

6. NEDO-23842, "Continuous Control Rod Withdrawal in the Startup Range," April 18, 1978.

7. USAR, Section 15.4.9.

8. Letter, P. Check (NRC) to G. Lainas (NRC), "BWR Scram Discharge System Safety Evaluation," December 1, 1980, as attached to NRC Generic Letter dated December 9, 1980.

9. NEDO-30851-P-A, "Technical Specification Improvement Analyses for BWR Reactor Protection System,"

March 1988.

10. NEDO-32291-A, "System Analyses for Elimination of Selected Response Time Testing Requirements," January 1994.

11. Calculation IP-0-0002.

12. Calculation IP-0-0024.

13. Risk Management Document No. 1073, "Scram Discharge Volume Level Instrument Surveillance Interval Extension Risk Assessment,". dated November 17, 2006.

CLINTON B 3.3-30 Revision No. 14-2

SRM Instrumentation B 3.3.1.2 BASES SURVEILLANCE SR 3.3.1.2.1 and SR 3.3.1.2.3 (continued)

REQUIREMENTS The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.

SR 3.3.1.2.2 To provide adequate coverage of potential reactivity changes in the core, one SRM is required to be OPERABLE in the quadrant where CORE ALTERATIONS are being performed, and the other OPERABLE SRM must be in an adjacent quadrant containing fuel. Note 1 states that this SR is required to be met only during CORE ALTERATIONS. It is not required to be met at other times in MODE 5 since core reactivity changes are not occurring. This Surveillance consists of a review of plant logs to ensure that SRMs required to be OPERABLE for given CORE ALTERATIONS are, in fact, OPERABLE.

In the event that only one SRM is required to be OPERABLE, per Table 3.3.1.2-1, footnote (b), only the a. portion of this SR is required. Note 2 clarifies that more than one of the three requirements can be met by the same OPERABLE SRM.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.2.4 This Surveillance consists of a verification of the SRM instrument readout to ensure that the SRM reading is greater than a specified minimum count rate. This ensures that the detectors are indicating count rates indicative of neutron flux levels within the core. Verification of the signal to noise ratio also ensures that the detectors are inserted to a normal operating level. In a fully withdrawn condition, the detectors are sufficiently removed from the fueled (continued)

CLINTON B 3.3-36 Revision No. 14-2

SRM Instrumentation B 3.3.1.2 BASES SURVEILLANCE SR 3.3.1.2.4 (continued)

REQUIREMENTS region of the core to essentially eliminate neutrons from reaching the detector. Any count rate obtained while fully withdrawn is assumed to be "noise" only. With few fuel assemblies loaded, the SRMs will not have a high enough count rate to satisfy the SR. Therefore, allowances are made for loading sufficient "source" material, in the form of irradiated fuel assemblies, to establish the minimum count rate.

To accomplish this, the SR is modified by a Note thatstates that the count rate is not required to be met on an SRM that has less than or equal to four fuel assemblies adjacent to the SRM and no other fuel assemblies are in the associated core quadrant. With four or less fuel assemblies loaded around each SRM and no other fuel assemblies in the associated quadrant, even with a control rod withdrawn the configuration will not be critical.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to count rate values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 1).

SR 3.3.1.2.5 Performance of a CHANNEL FUNCTIONAL TEST demonstrates the associated channel will function properly. 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 Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.3-37 Revision No. 14-2

/ SRM Instrumentation B 3.3.1.2 BASES SURVEILLANCE SR 3.3.1.2.5 (continued)

REQUIREMENTS The Note to the Surveillance allows the Surveillance to be delayed until entry into the specified condition of the Applicability. The SR must be performed in MODE 2 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of entering MODE 2 with IRMs on Range 2 or below.

The allowance to enter the Applicability with the Frequency not met is reasonable, based on the limited time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowed after entering the Applicability and the inability to perform the Surveillance while at higher power levels.

Although the Surveillance could be performed while on IRM Range 3, the plant would not be expected to maintain steady state operation at this power level. In this event, the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is reasonable, based on the SRMs being otherwise verified to be OPERABLE (i.e., satisfactorily performing the CHANNEL CHECK) and the time required to perform the Surveillances.

SR 3.3.1.2.6 Performance of a CHANNEL CALIBRATION verifies the performance of the SRM detectors and associated circuitry.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The neutron detectors are excluded from the CHANNEL CALIBRATION because they cannot readily be adjusted. The detectors are fission chambers that are designed to have a relatively constant sensitivity over the range, and with an accuracy specified for a fixed useful life.

The Note to the Surveillance allows the Surveillance to be delayed until entry into the specified condition of the Applicability. The SR must be performed in MODE 2 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of entering MODE 2 with IRMs on Range 2 or below. The allowance to enter the Applicability with.the Frequency not met is reasonable, based on the limited time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowed after entering the Applicability and the inability to perform the Surveillance while at higher power levels.

Although the Surveillance could be performed while on IRM Range 3, the plant would not be expected to maintain steady state operation at this power level. In this event, the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is reasonable, based on the SRMs being otherwise verified to be OPERABLE (i.e., satisfactorily (continued CLINTON B 3.3-38 Revision No. 14-2

OPRM Instrumentation B 3.3.1.3 BASES SURVEILLANCE For the following OPRM instrumentation Surveillances, REQUIREMENTS both OPRM modules are tested, although only one is required (continued) to satisfy the Surveillance Requirement.

SR 3.3.1.3.1 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.3.2 LPRM gain settings are determined from the local flux profiles measured by the Traversing Incore Probe (TIP)

System. This establishes the relative local flux profile for appropriate representative input to the APRM System. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.3.3 The CHANNEL CALIBRATION is a complete check of the instrument loop. 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. Calibration of the channel provides a check of the internal reference voltage and the internal processor clock frequency. It also compares the desired trip setpoint with those in the processor memory. Since the OPRM is a digital system, the internal reference voltage and processor clock frequency are, in turn, used to automatically calibrate the internal analog to digital converters. The nominal setpoints for the period based detection algorithm are specified in the Core Operating Limits Report (COLR) . As noted, neutron detectors are excluded from CHANNEL CALIBRATION because of the difficulty of simulating a meaningful signal. Changes in neutron detector sensitivity are compensated for by performing the LPRM calibration against the TIPs (SR 3.3.1.1.8). SR 3.3.1.1.8 thus also ensures the operability of the OPRM instrumentation.

The nominal setpoints for the OPRM trip function for the period based detection algorithm (PBDA) are specified in the COLR. The PBDA trip setpoints are the number of confirmation counts required to permit a trip signal and the peak to average amplitude required to generate a trip signal.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.3-39f Revision No. 14-2

OPRM Instrumentation B 3.3.1.3 BASES SURVEILLANCE SR 3.3.1.3.4 REQUIREMENTS (continued) The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channel. The functional testing of control rods in LCO 3.1.3, "Control Rod OPRABILITY," and scram discharge volume (SDV) vent and drain valves in LCO 3.1.8, "Scram Discharge Volume (SDV) Vent and Drain Valves," overlaps this Surveillance to provide complete testing of the assumed safety function. The OPRM self-test function may be utilized to perform this testing for those components that it is designed to monitor.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.3.5 This SR ensures that trips initiated from the OPRM System will not be inadvertently bypassed when THERMAL POWER is 25% RTP and recirculation drive flow is

the value corresponding to 60% of rated core flow. This normally involves calibration of the bypass channels. The 25% RTP value is the plant specific value for the enable region, as described in Reference 10.

These values have been conservatively selected so that specific, additional uncertainty allowances need not be applied. Specifically, for the THERMAL POWER, the Average Power Range Monitor (APRM) establishes the reference signal to enable the OPRM System at 25% RTP. Thus, the nominal setpoints corresponding to the values listed above (25% RTP and the value corresponding to 60% of rated core flow) will be used to establish the enabled region of the OPRM System trips. (References 1, 2, 6, 10, and 11)

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.3.6 This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis (Reference 6). The OPRM self-test function may be utilized to perform this testing for those components it is designed to monitor. The RPS RESPONSE TIME acceptance criteria are included in plant Surveillance procedures.

As noted, neutron detectors are excluded from RPS RESPONSE TIME testing because the principles of detector operation virtually ensure an instantaneous response time. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.3-39g Revision No. 14-2

OPRM Instrumentation B 3.3.1.3 BASES (continued)

REFERENCES 1. NEDO-31960, "BWR Owners' Group Long-Term Stability Solutions Licensing Methodology," June 1991.

2. NEDO-31960, "BWR Owners' Group Long-Term Stability Solutions Licensing Methodology," Supplement 1, March 1992.

3. NRC Letter, A. Thadani to L. A. England, "Acceptance for Referencing of Topical Reports NEDO-31960, Supplement 1, 'BWR Owners' Group Long-Term Stability Solutions Licensing Methodology'," July 12, 1994.

4. Generic Letter 94-02, "Long-Term Solutions and Upgrade of Interim Operating Recommendations for Thermal-Hydraulic Instabilities in Boiling Water Reactors,"

July 11, 1994.

5. BWROG Letter BWROG-94079, "Guidelines for Stability Interim Corrective Action," June 6, 1994.

6. NEDO-32465-A, "BWR Owners' Group Reactor Stability Detect and Suppress Solution Licensing Basis Methodology and reload Application," August 1996.

7. CENPD-400-P, Rev. 01, "Generic Topical Report for the ABB Option III Oscillation Power Range Monitor (OPRM),"

May 1995.

8. NRC Letter, B. Boger to R. Pinelli, "Acceptance of Licensing Topical Report CENPD-400-P, 'Generic Topical Report for the ABB Option III Oscillation Power Range Monitor (OPRM)'," August 16, 1995.

9. NEDO-30851-P-A, "Technical Specification Improvement Analyses for BWR Reactor Protection System," March 1988.

10. NEDC-32989P, "Safety Analysis Report for Clinton Power Station Extended Power Uprate," dated June 2001.

11. Letter from K. P. Donovan (BWR Owners' Group) to U. S.

NRC, "Guidelines for Stability Option III 'Enabled Region'," dated September 17, 1996.

CLINTON B 3.3-39h Revision No. 14-2

Control Rod Block Instrumentation B 3.3.2.1 BASES ACTIONS C.l and C.2 (continued)

If one Reactor Mode Switch-Shutdown Position control rod withdrawal block channel is inoperable, the remaining OPERABLE channel is adequate to perform the control rod withdrawal block function. Required Action C.1 and Required Action C.2 are consistent with the normal action of an OPERABLE Reactor Mode Switch-Shutdown Position Function to maintain all control rods inserted. Therefore, there is no distinction between Required Actions for the Conditions of one or two channels inoperable. In both cases (one or both channels inoperable), suspending all control rod withdrawal immediately, and immediately initiating action to fully insert all insertable control rods in core cells containing one or more fuel assemblies will ensure that the core is subcritical, with adequate SDM ensured by LCO 3.1.1, "SHUTDOWN MARGIN (SDM) ." Control rods in core cells containing no fuel assemblies do not affect the reactivity of the core and are therefore not required to be inserted.

Action must continue until all insertable control rods in core cells containing one or more fuel assemblies are fully inserted.

SURVEILLANCE As noted at the beginning of the SR, the SRs for each REQUIREMENTS Control Rod Block instrumentation Function are found in the SRs column of Table 3.3.2.1-1.

The Surveillances are also modified by a Note to indicate that 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 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , provided the associated Function maintains control rod block capability. 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.

This Note is based on the reliability analysis (Ref. 7) assumption of the average time required to perform channel Surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that a control block will be initiated when necessary.

(continued)

CLINTON B 3.3-45 Revision No. 1-1

Control Rod Block Instrumentation B 3.3.2.1 BASES SURVEILLANCE SR 3.3.2.1.1, SR 3.3.2.1.2, SR 3.3.2.1.3, and REQUIREMENTS SR 3.3.2.1.4 (continued)

The CHANNEL FUNCTIONAL TESTS for the RPC and RWL are performed by attempting to withdraw a control rod not in compliance with the prescribed sequence and verifying that a control rod block occurs. 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. SR 3.3.2.1.1 verifies proper operation of the two-notch withdrawal limit of the RWL and SR 3.3.2.1.2 verifies proper operation of the four-notch withdrawal limit of the RWL. SR 3.3.2.1.3 and SR 3.3.2.1.4 verify proper operation of the RPC. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology. As noted, the SRs are not required to be performed until 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after specified conditions are met (e.g., after any control rod is withdrawn in MODE 2). This allows entry into the appropriate conditions needed to perform the required SRs. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months allowance is based on operating experience and in consideration of providing a reasonable time in which to complete the SRs. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.2.1.5 The LPSP is the point at which the RPCS makes the transition between the function of the RPC and the RWL. This transition point is automatically varied as a function of power. This power level is inferred from the first stage turbine pressure (one channel to each trip system). These power setpoints must be verified periodically to be within the Allowable Values.

If any LPSP is nonconservative such that the RPC is bypassed at

16.7% RTP, then the RPC is considered inoperable.

Similarly, if the LPSP is nonconservative such that the RWL low power Function is bypassed at > 29.2% RTP, (e.g., due to open main steam line drain(s), main turbine bypass valve(s),

or other reasons), then the RWL is considered inoperable.

Since this channel has both upper and lower required limits, it is not allowed to be placed in a condition to enable either the RPC or RWL Function.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.3-46 Revision No. 14-2

Control Rod Block Instrumentation B 3.3.2.1 BASES SURVEILLANCE SR 3.3.2.1.6 REQUIREMENTS (continued) This SR ensures the high power function of the RWL is not bypassed when power is > 70% RTP. The power level is inferred from turbine first stage pressure signals.

Periodic testing of the HPSP channels is required to verify the HPSP to be less than or equal to the limit. This involves calibration of the HPSP. Adequate margins in accordance with setpoint methodologies are included.

If the HPSP is nonconservative such that the RWL high power Function is bypassed at > 70% RTP, (e.g., due to open main steam line drain(s), main turbine bypass valve(s), or other reasons), then the RWL is considered inoperable.

Alternatively, the HPSP can be placed in the conservative condition (nonbypass) . If placed in the nonbypassed condition, the SR is met and the RWL would not be considered inoperable.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.2.1.7 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies that 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. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.2.1.8 The CHANNEL FUNCTIONAL TEST for the Reactor Mode Switch-Shutdown Position Function is performed by attempting to withdraw any control rod with the reactor mode switch in the shutdown position and verifying a control rod block occurs.

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.

As noted in the SR, the Surveillance is not required to be performed until 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after the reactor mode switch is in (continued)

CLINTON B 3.3-47 Revision No. 14-2

Control Rod Block Instrumentation B 3.3.2.1 BASES SURVEILLANCE SR 3.3.2.1.8 (continued)

REQUIREMENTS the shutdown position, since testing of this interlock with the reactor mode switch in any other position cannot be performed without using jumpers, lifted leads, or movable limits. This allows entry into MODES 3 and 4 if the Frequency is not met per SR 3.0.2. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months allowance is based on operating experience and in consideration of providing a reasonable time in which to complete the SRs.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.2.1.9 LCO 3.1.3 and LCO 3.1.6 may require individual control rods to be bypassed in RACS to allow insertion of an inoperable control rod or correction of a control rod pattern not in compliance with BPWS. With the control rods bypassed in the RACS, the RPC will not control the movement of these bypassed control rods. Individual control rods may also be required to be bypassed to allow continuous withdrawal for determining the location of leaking fuel assemblies or adjustment of control rod speed. To ensure the proper bypassing and movement of those affected control rods, a second licensed operator or other qualified member of the technical staff must verify the bypassing and movement of these control rods is in conformance with applicable analyses. Compliance with this SR allows the RPC and RWL to be OPERABLE with these control rods bypassed.

REFERENCES 1. USAR, Section 7.6.1.7.

2. USAR, Section 15.4.2.

3. NEDE-24011-P-A, "General Electric Standard Application for Reload Fuel" (latest approved revision).

4. NEDO-21231, "Banked Position Withdrawal Sequence,"

January 1977.

5. NRC SER, Acceptance of Referencing of Licensing Topical Report NEDE-24011-P-A, "General Electric Standard Application for Reactor Fuel, Revision 8, Amendment 17," December 27, 1987.

6. NEDC-30851-P-A, "Technical Specification Improvement Analysis for BWR Control Rod Block Instrumentation,"

October 1988.

7. GENE-770-06-1, "Addendum to Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications," February 1991.

CLINTON B 3.3-48 Revision No. 14-2

PAM Instrumentation B 3.3.3.1 BASES ACTIONS F.1 (continued) installed PAM channels, justify the areas in which they are not equivalent, and provide a schedule for restoring the normal PAM channels. The Special Report shall be submitted in accordance with 10 CFR 50.4 within 14 days of entering Condition F.

SURVEILLANCE The following SRs apply to each PAM instrumentation Function REQUIREMENTS in Table 3.3.3.1-1, except as noted below.

SR 3.3.3.1.1 Performance of the CHANNEL CHECK ensures that a gross instrumentation failure has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value.

Significant deviations between instrument channels could be an indication of excessive instrument drift in one of the channels or of something even more serious. CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION. The high radiation instrumentation should be compared to similar plant instruments located throughout the plant.

Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, including isolation, indication, and readability. If a channel is outside the criteria, it may be an indication that the sensor or the signal processing equipment has drifted outside its limit.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of those displays associated with the required channels of this LCO.

(continued)

CLINTON B 3.3-58 Revision No. 14-2

PAM Instrumentation B 3.3.3.1 BASES SURVEILLANCE SR 3.3.3.1.2 (Deleted)

REQUIREMENTS (continued) SR 3.3.3.1.3 CHANNEL CALIBRATION is a complete check of the instrument loop including the sensor. The test verifies that the channel responds to the measured parameter with the necessary range and accuracy. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

The CHANNEL CALIBRATION of the Primary Containment and Drywell Area Radiation Functions consists of an electronic calibration of the channel, not including the detector, for range decades above 10 R per hour and a one point calibration check of the detector below 10 R per hour with an installed or portable gamma source.

REFERENCES 1. Regulatory Guide 1.97, "Instrumentation for Light-Water Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident," Revision 3, May 1983.

2. SSER 5, Section 7.5.3.1.

3. USAR, Table 7.1-13.

4. USAR Section 7.5.1.4.2.4.

CLINTON B 3.3-59 Revision No. 14-2

Remote Shutdown System B 3.3.3.2 BASES ACTIONS A.l (continued)

Condition A addresses the situation where one or more required Functions of the Remote Shutdown System is inoperable. This includes the control and transfer switches for any required Function.

The Required Action is to restore the Function (both divisions, if applicable) to OPERABLE status within 30 days.

The Completion Time is based on operating experience and the low probability of an event that would require evacuation of the control room.

B.1 If the Required Action and associated Completion Time of Condition A are 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 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed Completion Time is reasonable, based on operating experience, to reach the required MODE from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.3.3.2.1 REQUIREMENTS Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value.

Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between eachCHANNEL CALIBRATION.

Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is (continued)

CLINTON B 3.3-63 Revision No. 14-2

Remote Shutdown System B 3.3.3.2 BASES SURVEILLANCE SR 3.3.3.2.1 (continued)

REQUIREMENTS outside the criteria, it may be an indication that the sensor or the signal processing equipment has drifted outside its limit. As specified in the Surveillance, a CHANNEL CHECK is only required for those channels that are normally energized.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.3.2.2 SR 3.3.3.2.2 verifies each required Remote Shutdown System transfer switch and control circuit performs the intended function. This verification is performed from the remote shutdown panel and locally, as appropriate. Operation of the equipment from the remote shutdown panel and the local control stations are not necessary. The Surveillance can be satisfied by performance of a continuity check. This will ensure that if the control room becomes inaccessible, the plant can be placed and maintained in MODE 3 from the remote shutdown panel and the local control stations. However, this Surveillance is not required to be performed only during a plant outage. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.3.2.3 CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. The test verifies the channel responds to measured parameter values with the necessary range and accuracy.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. 10 CFR 50, Appendix A, GDC 19.

2. Operational Requirements Manual, Attachment 1.

3. NUREG-0853, "Safety Evaluation Report Related to the Operation of Clinton Power Station, Unit No. 1,"

Supplement No. 6, July 1986, Section 7.4.3.1.

CLINTON B 3.3-64 Revision No. 14-2

EOC-RPT Instrumentation B 3.3.4.1 BASES (continued)

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 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , provided the associated Function maintains EOC-RPT trip capability. 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. This Note is based on the reliability analysis (Ref. 6) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the recirculation pumps will trip when necessary.

SR 3.3.4.1.1 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. 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. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.4.1.2 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 Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.3-72 Revision No. 14-2

EOC-RPT Instrumentation B 3.3.4.1 BASES SURVEILLANCE SR 3.3.4.1.3 REQUIREMENTS (continued) The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channel. The system functional test of the pump breakers is included as a part of this test, overlapping the LOGIC SYSTEM FUNCTIONAL TEST, to provide complete testing of the associated safety function. Therefore, if a breaker is incapable of operating, the associated instrument channels would also be inoperable.

The Self Test System may be utilized to perform this testing for those components that it is designed to monitor.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.4.1.4 This SR ensures that an EOC-RPT initiated from the TSV Closure and TCV Fast Closure, Trip Oil Pressure-Low Functions will not be inadvertently bypassed when THERMAL POWER is > 33.3% RTP. This involves calibration of the bypass channels. Adequate margins for the instrument setpoint methodologies are incorporated into the actual setpoint. If any bypass channel's setpoint is nonconservative such that the Functions are bypassed at

> 33.3% RTP (e.g., due to open main steam line drain(s),

main turbine bypass valve(s) or other reasons), the affected TSV Closure and TCV Fast Closure, Trip Oil Pressure-Low Functions are considered inoperable. Alternatively, the bypass channel can be placed in the conservative condition (nonbypass) . If placed in the nonbypass condition, this SR is met and the channel considered OPERABLE.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.3-73 Revision No. 14-2

EOC-RPT Instrumentation B 3.3.4.1 BASES SURVEILLANCE SR 3.3.4.1.5 REQUIREMENTS (continued) This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis. The EOC-RPT SYSTEM RESPONSE TIME acceptance criteria are included in applicable plant procedures and include an assumed RPT breaker interruption time of 80 milliseconds. This assumed RPT breaker interruption time is validated by the performance of periodic mechanical timing checks, contact wipe and erosion checks, and high potential tests on each breaker in accordance with plant procedures at least once per 48 months. The acceptance criterion for the RPT breaker mechanical timing check shall be < 41 milliseconds (for trip coil TC2).

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to EOC-RPT SYSTEM RESPONSE TIME values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 7).

(continued)

CLINTON B 3.3-74 Revision No. 14-2

EOC-RPT Instrumentation B 3.3.4.1 BASES (continued)

REFERENCES 1. USAR, Section 7.6.1.8.

2. USAR, Section 5.2.2.

3. USAR, Sections 15.1.1, 15.1.2, and 15.1.3.

4. USAR, Sections 15.2.2, 15.2.3, and 15.2.5.

5. USAR, Sections 15.3.2 and 15.3.3.

6. GENE-770-06-1, "Bases for Changes To Surveillance Test Intervals And Allowed Out-Of-Service Times For Selected Instrumentation Technical Specifications,"

February 1991.

7. Calculation IP-0-0024.

CLINTON B 3.3-75 Revision No. 14-2

ATWS-RPT Instrumentation B 3.3.4.2 BASES (continued)

SURVEILLANCE REQUIREMENTS SR 3.3.4.2.1 Performance of the CHANNEL CHECK ensures that gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value.

Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying that the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the required channels of this LCO.

(continued)

CLINTON B 3. 3-82 Revision No. 14-2

ATWS-RPT Instrumentation B 3.3.4.2 BASES SURVEILLANCE SR 3.3.4.2.2 REQUIREMENTS (continued) A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. 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.

Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.4.2.3 Calibration of trip units provides a check of the actual trip setpoints. The channel must be declared inoperable if the trip setting is discovered to be less conser.vative than the Allowable Value specified in SR 3.3.4.2.4. If the trip setting is discovered to be less conservative than the setting accounted for in the appropriate setpoint methodology, but is not beyond the Allowable Value, the channel performance is still within the requirements of the plant safety analysis. Under these conditions, the setpoint must be readjusted to be equal to or more conservative than accounted for in the appropriate setpoint methodology.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.4.2.4 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies that 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 Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.3-83 Revision No. 14-2

ATWS-RPT Instrumentation B 3.3.4.2 BASES SURVEILLANCE SR 3.3.4.2.5 REQUIREMENTS (continued) The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channel. The system functional test of the pump breakers, included as part of this Surveillance, overlaps the LOGIC SYSTEM FUNCTIONAL TEST to provide complete testing of the assumed safety function. Therefore, if a breaker is incapable of operating, the associated instrument channel(s) would be inoperable.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. USAR, Section 7.7.1.25.2 CLINTON B 3.3-84 Revision No. 14-2

ECCS Instrumentation B 3.3.5.1 BASES SURVEILLANCE taken. This Note is based on the reliability analysis REQUIREMENTS (Ref. 4) assumption of the average time required to perform (continued) channel Surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the ECCS will initiate when necessary.

SR 3.3.5.1.1 Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value.

Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

Agreement criteria are determined by the plant staff, based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.

SR 3;3.5.1.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. For series Functions, a separate CHANNEL FUNCTIONAL TEST is not required for each Function, provided each Function is tested. 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.

(continued)

CLINTON B 3.3-119 Revision No. 14-2

ECCS Instrumentation B 3.3.5.1 BASES SURVEILLANCE SR 3.3.5.1.2 (continued)

REQUIREMENTS Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.5.1.3 The calibration of ATMs provides a check of the actual trip setpoints. The channel must be declared inoperable if the trip setting is discovered to be not within its required Allowable Value specified in Table 3.3.5.1-1. If the trip setting is discovered to be less conservative than accounted for in the appropriate setpoint methodology, but is not beyond the Allowable Value, the channel performance is still within the requirements of the plant safety analyses. Under these conditions, the setpoint must be readjusted to be equal to or more conservative than the setting accounted for in the appropriate setpoint methodology.

The SR 3.3.5.1.3 calibration for selected Functions is modified by a Note as identified in Table 3.3.5.1-1. This Note, which applies only to those Functions identified in Table 3.3.5.1-1, is divided into three parts. Part 1 of the Note requires evaluation of instrument performance for the condition where the as-found setting for these instrument channels is outside its As-Found Tolerance (AFT) but conservative with respect to the Allowable Value.

Evaluation of instrument performance will verify that the instrument will continue to behave in accordance with design-basis assumptions. The purpose of the assessment is to ensure confidence in the instrument performance prior to returning the instrument to service. Initial evaluation will be performed by the technician performing the surveillance who will evaluate the instrument's ability to maintain a stable setpoint within the As-Left Tolerance (ALT). The technician's evaluation will be reviewed by on-shift operations personnel during the approval of the surveillance data. Subsequent to returning the instrument to service, the deviation is entered into the Corrective Action Program. In accordance with procedures, entry into the Corrective Action Program will require review and documentation of the condition for operability by on-shift operations personnel. Additional evaluation and potential corrective actions as necessary will ensure that any as-found setting found outside the AFT is evaluated for long-term operability trends. If the as-found channel setpoint is not conservative with respect to the Allowable Value, the (continued)

CLINTON B 3.3-120 Revision No. 14-2

ECCS Instrumentation B 3.3.5.1 BASES SURVEILLANCE SR 3.3.5.1.3 (continued)

REQUIREMENTS channel shall be declared inoperable. Part 2 of the Note requires that the instrument channel setpoint shall be reset to within the ALT of the Actual Trip Setpoint (ATSP) . The ATSP is equivalent to or more conservative than the Nominal Trip Setpoint (NTSP). The NTSP is the limiting value of the sensed process variable at which a trip may be set in accordance with the methodology documented in the ORM.

Therefore, the NTSP is equivalent to the Limiting Safety System Setting (LSSS) required by 10 CFR 50.36, "Technical specifications." The Actual Trip Setpoint is also calculated in accordance with the plant-specific setpoint methodology as documented in the CPS ORM and may include additional margin. The ATSP will ensure that sufficient margin to the safety and/or analytical limit is maintained.

If the as-left instrument channel setpoint cannot be returned to within the ALT of the Actual Trip Setpoint, then the channel shall be declared inoperable. Part 3 of the Note indicates that the Nominal Trip Setpoint and the methodology used to determine the Nominal Trip Setpoint, the As-Found Tolerance and the As-Left Tolerance bands are specified in the ORM.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.5.1.4 and SR 3.3.5.1.6 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 SR 3.3.5.1.4 and SR 3.3.5.1.6 calibrations for selected Functions are modified by a Note as identified in Table 3.3.5.1-1. This Note, which applies only to those Functions identified in Table 3.3.5.1-1, is divided into three parts.

Part 1 of the Note requires evaluation of instrument performance for the condition where the as-found setting for these instrument channels is outside its As-Found Tolerance (AFT) but conservative with respect to the Allowable Value.

Evaluation of instrument performance will verify that the instrument will continue to behave in accordance with design-basis assumptions. The purpose of the assessment is to ensure confidence in the instrument performance prior to returning the instrument to service. Initial evaluation will be performed by the technician performing the surveillance who will evaluate the instrument's ability to maintain a stable setpoint within the As-Left Tolerance (ALT). The technician's evaluation will be reviewed by on-shift operations personnel during the approval of the (continued)

CLINTON B 3.3-120a Revision No. 14-2

ECCS Instrumentation B 3.3.5.1 BASES SURVEILLANCE SR 3.3.5.1.4 and SR 3.3.5.1.6 (continued)

REQUIREMENTS surveillance data. Subsequent to returning the instrument to service, the deviation is entered into the Corrective Action Program. In accordance with procedures, entry into the Corrective Action Program will require review and documentation of the condition for operability by on-shift operations personnel. Additional evaluation and potential corrective actions as necessary will ensure that any as-found setting found outside the AFT is evaluated for long-term operability trends. If the as-found channel setpoint is not conservative with respect to the Allowable Value, the channel shall be declared inoperable. Part 2 of the Note requires that the instrument channel setpoint shall be reset to within the ALT of the Actual Trip Setpoint (ATSP) . The ATSP is equivalent to or more conservative than the Nominal Trip Setpoint (NTSP). The NTSP is the limiting value of the sensed process variable at which a trip may be set in accordance with the methodology documented in the ORM.

Therefore, the NTSP is equivalent to the Limiting Safety System Setting (LSSS) required by 10 CFR 50.36, "Technical specifications." The Actual Trip Setpoint is also calculated in accordance with the plant-specific setpoint methodology as documented in the CPS ORM and may include additional margin. The ATSP will ensure that sufficient margin to the safety and/or analytical limit is maintained.

If the as-left instrument channel setpoint cannot be returned to within the ALT of the Actual Trip Setpoint, then the channel shall be declared inoperable. Part 3 of the Note indicates that the Nominal Trip Setpoint and the methodology used to determine the Nominal Trip Setpoint, the As-Found Tolerance and the As-Left Tolerance bands are specified in the ORM.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.3-120b Revision No. 14-2

ECCS Instrumentation B 3.3.5.1 BASES SURVEILLANCE SR 3.3.5.1.5 REQUIREMENTS (continued) The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic for a specific channel. The system functional testing performed in LCO 3.5.1, LCO 3.5.2, LCO 3.7.2, LCO 3.8.1, and LCO 3.8.2 overlaps this Surveillance to provide complete testing of the assumed safety function.

The Self Test System may be utilized to perform this testing for those components that it is designed to monitor.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. USAR, Section 5.2.2.

2. USAR, Section 6.3.

3. USAR, Chapter 15.

4. NEDC-30936-P-A, "BWR Owners' Group Technical Specification Improvement Analyses for ECCS Actuation Instrumentation, Part 2," December 1988.

CLINTON B 3.3-121 Revision No. 14-2

RCIC System Instrumentation B 3.3.5.2 BASES SURVEILLANCE (a) for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for Functions 2 and 5; and (b) for up REQUIREMENTS to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for Functions 1, 3, and 4 provided the associated (continued) Function maintains trip capability. 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.

This Note is based on the reliability analysis (Ref. 2) assumption of the average time required to perform channel Surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the RCIC will initiate when necessary.

SR 3.3.5.2.1 Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value.

Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying that the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The CHANNEL CHECK supplements less formal, but more frequent, checks of channel status during normal operational use of the displays associated with the channels required by the LCO.

SR 3.3.5.2.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. 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. Any setpoint adjustment shall (continued)

CLINTON B 3.3-132 Revision No. 14-2

RCIC System Instrumentation B 3.3.5.2 BASES SURVEILLANCE SR 3.3.5.2.2 (continued)

REQUIREMENTS be consistent with the assumptions of the current plant specific setpoint methodology.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.5.2.3 The calibration of analog trip modules provides a check of the actual trip setpoints. The channel must be declared inoperable if the trip setting is discovered to be less conservative than the Allowable Value specified in Table 3.3.5.2-1. If the trip setting is discovered to be less conservative than accounted for in the appropriate setpoint methodology, but is not beyond the Allowable Value, the channel performance is still within the requirements of the plant safety analysis. Under these conditions, the setpoint must be re-adjusted to be equal to or more conservative than accounted for in the appropriate setpoint methodology.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.5.2.4 and SR 3.3.5.2.6 CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter with 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 Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.5.2.5 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic for a specific channel. The system functional testing performed in LCO 3.5.3 overlaps this Surveillance to provide complete testing of the safety function.

(continued)

CLINTON B 3.3-133 Revision No. 14-2

RCIC System Instrumentation B 3.3.5.2 BASES SURVEILLANCE SR 3.3.5.2.5 (continued)

REQUIREMENTS The Self Test System may be utilized to perform this testing for those components that it is designed to monitor.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. USAR, Section 15.4.9.

2. NEDE-770-06-2, "Addendum to Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications," February 1991.

3. USAR, Section 5.4.6.

CLINTON B 3.3-134 Revision No. 14-2

Primary Containment and Drywell Isolation Instrumentation B 3.3.6.1 BASES (continued)

SURVEILLANCE As noted at the beginning of the SRs, the SRs for each REQUIREMENTS Primary Containment and Drywell Isolation Instrumentation Function are found in the SRs column of Table 3.3.6.1-1.

The Surveillances are also modified by a Note to indicate that 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 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the associated Function maintains isolation capability. Isolation capability may be maintained by ensuring that a sufficient number or arrangement of channels is maintained OPERABLE to effect the trip function, or by maintaining the affected primary containment and drywell isolation valves closed during performance of the surveillance. 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.

This Note is based on the reliability analysis (Refs. 5 and

6) assumption of the average time required to perform channel Surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the isolation valves will isolate the penetration flow path(s) when necessary.

SR 3.3.6.1.1 Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value.

Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

Agreement criteria are determined by the plant staff, based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.3-170 Revision No. 14-2

Primary Containment and Drywell Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE SR 3.3.6.1.1 (continued)

REQUIREMENTS The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.

SR 3.3.6.1.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. For series Functions, a separate CHANNEL FUNCTIONAL TEST is not required for each Function, provided each Function is tested. 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.

Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.6.1.3 The calibration of analog trip modules consists of a test to provide a check of the actual trip setpoints. The channel must be declared inoperable if the trip setting is discovered to be less conservative than the Allowable Value specified in Table 3.3.6.1-1. If the trip setting is discovered to be less conservative than accounted for in the appropriate setpoint methodology, but is not beyond the Allowable Value, the channel performance is still within the requirements of the plant safety analysis. Under these conditions, the setpoint must be readjusted to be equal to or more conservative than accounted for in the appropriate setpoint methodology.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.6.1.4, SR 3.3.6.1.5, and SR 3.3.6.1.8 CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel (continued)

CLINTON B 3. 3-171 Revision No. 14-2

Primary Containment and Drywell Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE SR 3.3.6.1.4, SR 3.3.6.1.5, and SR 3.3.6.1.8 (continued)

REQUIREMENTS 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 Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.6.1.6 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required isolation logic for a specific channel. The system functional testing performed on PCIVs in LCO 3.6.1.3 and on drywell isolation valves in LCO 3.6.5.3 overlaps this Surveillance to provide complete testing of the assumed safety function. (Likewise, system functional testing pe-rformed pursuant to LCO 3.7.1 overlaps this Surveillance to provide complete testing for verifying automatic actuation capability for the Division 1 and 2 SX subsystems.) The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

The Self Test System may be utilized to perform this testing for those components that it is designed to monitor.

SR 3.3.6.1.7 This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis. Testing is performed only on channels where the assumed response time does not correspond to the diesel generator (DG) start time. For channels assumed to respond within the DG start time, sufficient margin exists in the 12 second start time when compared to the typical channel response time (milliseconds) so as to assure adequate response without a specific measurement test. The instrument response times must be added to the MSIV closure times to obtain the ISOLATION SYSTEM RESPONSE TIME.

ISOLATION SYSTEM RESPONSE TIME acceptance criteria are included in applicable plant procedures.

(continued)

CLINTON B 3.3-172 Revision No. 14-2

Primary Containment and Drywell Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE SR 3.3.6.1.7 (continued)

REQUIREMENTS As noted, the associated sensors are not required to be response time tested. Response time testing for the remaining channel components, including the ATMs, is required. This is supported by Reference 7.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to ISOLATION SYSTEM RESPONSE TIME values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 8).

REFERENCES 1. USAR, Section 6.2.

2. USAR, Chapter 15.

3. NEDO-31466, "Technical Specification Screening Criteria Application and Risk Assessment," November 1987.

4. USAR, Section 9.3.5.

5. NEDC-31677-P-A, "Technical Specification Improvement Analysis for BWR Isolation Actuation Instrumentation,"

June 1989.

6. NEDC-30581-P-A, Supplement 2, "Technical Specifications Improvement Analysis for BWR Isolation Instrumentation Common to RPS and ECCS Instrumentation," March 1989.

7. NEDO-32291-A, "System Analyses for Elimination of Selected Response Time Testing Requirements," January 1994.

8. Calculation IP-0-0028.

CLINTON B 3.3-173 Revision No. 14-2

Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES ACTIONS C.1.1, C.1.2, C.2.1, and C.2.2 (continued)

Alternatively, declaring the associated SCID(s) or SGT subsystem inoperable (Required Actions C.1.2 and C.2.2) is also acceptable since the Required Actions of the respective LCOs (LCO 3.6.4.2 and LCO 3.6.4.3) provide appropriate actions for the inoperable components.

One hour is sufficient for plant operations personnel to establish required plant conditions or to declare the associated components inoperable without challenging plant systems.

SURVEILLANCE As noted at the beginning of the SRs, the SRs for each REQUIREMENTS Secondary Containment Isolation instrumentation Function are located in the SRs column of Table 3.3.6.2-1.

The Surveillances are also modified by a Note to indicate that 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 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , provided the associated Function maintains secondary containment isolation capability. 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 Action(s) taken. This Note is based on the reliability analysis (Refs. 3 and 4) assumption of the average time required to perform channel Surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the SCIDs will isolate the associated penetration flow paths and the SGT System will initiate when necessary.

SR 3.3.6.2.1 Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the indicated parameter for one instrument channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of (continued)

CLINTON B 3.3-182 Revision No. 14-2

Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES SURVEILLANCE SR 3.3.6.2.1 (continued)

REQUIREMENTS excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

Agreement criteria are determined by the plant staff, based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.

SR 3.3.6.2.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. 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. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.6.2.3 Calibration of analog trip modules provides a check of the actual trip, setpoints. The channel must be declared inoperable if the trip setting is discovered to be less conservative than the Allowable Value specified in Table 3.3.6.2-1. If the trip setting is discovered to be less conservative than accounted for in the appropriate setpoint methodology, but is not beyond the Allowable Value, performance is still within the requirements of the plant safety analysis. Under these conditions, the setpoint must be readjusted to be equal to or more conservative than accounted for in the appropriate setpoint methodology.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.3-183 Revision No. 14-2

Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES SURVEILLANCE SR 3.3.6.2.4 and SR 3.3.6.2.6 REQUIREMENTS (continued) 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 Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.6.2.5 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required isolation logic for a specific channel. The system functional testing, performed on SCIDs and the SGT System in LCO 3.6.4.2 and LCO 3.6.4.3, respectively, overlaps this Surveillance to provide complete testing of the assumed safety function.

The Self Test System may be utilized to perform this testing for those components that it is designed to monitor. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.3-184 Revision No. 14-2

Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES (continued)

REFERENCES 1. USAR, Section 6.2.3.

2. USAR, Chapter 15.

3. NEDO-31677-P-A, "Technical Specification Improvement Analysis for BWR Isolation Actuation Instrumentation,"

July 1990.

4. NEDC-30851-P-A Supplement 2, "Technical Specifications Improvement Analysis for BWR Isolation Instrumentations Common to RPS and ECCS Instrumentation," March 1989.

5. USAR, Section 7.3.1.1.2.

6. USAR, Section 7.1.2.1.11.

7. USAR, Section 7.3.1.1.9.2.

8. USAR, Section 7.6.1.2.

CLINTON B 3.3-185 Revision No. 14-2

RHR Containment Spray System Instrumentation B 3.3.6.3 BASES SURVEILLANCE associated Conditions and Required Actions may be delayed REQUIREMENTS for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , provided the associated Function (continued) maintains RHR containment spray initiation capability. 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. This Note is based on the reliability analysis (Ref. 3) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the RHR containment spray will initiate when necessary.

SR 3.3.6.3.1 Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value.

Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.

(continued)

CLINTON B 3.3-194 Revision No. 14-2

RHR Containment Spray System Instrumentation B 3.3.6.3 BASES SURVEILLANCE SR 3.3.6.3.2 REQUIREMENTS (continued) A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure the entire channel will perform the intended function. For Series Functions, a separate CHANNEL FUNCTIONAL TEST is not required for each Function, provided each Function is tested. 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.

Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.6.3.3 The calibration of analog trip modules provides a check of the actual trip setpoints. The channel must be declared inoperable if the trip setting is discovered to be less conservative than the Allowable Value specified in Table 3.3.6.3-1. If the trip setting is discovered to be less conservative than accounted for in the appropriate setpoint methodology, but is not beyond the Allowable Value, the channel performance is still within the requirements of the plant safety analysis. Under these conditions, the setpoint must be readjusted to be equal to or more conservative than accounted for in the appropriate setpoint methodology.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.6.3.4 and SR 3.3.6.3.6 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies that 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 Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.3-195 Revision No. 14-2

RHR Containment Spray System Instrumentation B 3.3.6.3 BASES SURVEILLANCE SR 3.3.6.3.5 REQUIREMENTS (continued) The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic for a specific channel. The system functional testing performed in LCO 3.6.1.7, "Residual Heat Removal (RHR) Containment Spray," overlaps this Surveillance to provide complete testing of the assumed safety function.

The Self Test System may be utilized to perform this testing for those components that it is designed to monitor. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. USAR, Section 7.3.1.1.4.

2. USAR, Section 6.2.1.1.5.

3. GENE-770-06-1, "Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications,"

February 1991.

CLINTON B 3.3-196 Revision No. 14-2

SPMU System Instrumentation B 3.3.6.4 BASES (continued)

SURVEILLANCE As noted at the beginning of the SRs, the SRs for each SPMU REQUIREMENTS System Function are located in the SRs column of Table 3.3.6.4-1.

The Surveillances are also modified by a Note to indicate that 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 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , provided the associated Function maintains suppression pool makeup initiation capability.

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. This Note is based on the reliability analysis (Ref. 3) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the SPMU will initiate when necessary.

SR 3.3.6.4.1 Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value.

Significant deviations between the instrument channels could be an indication of excessive instrument~drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

Agreement criteria are determined by the plant staff, based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the required channels of the LCO.

(continued)

CLINTON B 3.3-205 Revision No. 14-2

SPMU System Instrumentation B 3.3.6.4 BASES SURVEILLANCE SR 3.3.6.4.2 REQUIREMENTS (continued) A CHANNEL FUNCTIONAL TEST' is performed on each required channel to ensure the entire channel will perform the intended function. For Series Functions, a separate CHANNEL FUNCTIONAL TEST is not required for each Function, provided each Function is tested. 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.

Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.6.4.3 and SR 3.3.6.4.4 The calibration of analog trip modules and analog comparator units provides a check of the actual trip setpoints. The channel must be declared inoperable if the trip setting is discovered to be less conservative than the Allowable Value specified in Table 3.3.6.4-1. If the trip setting is discovered to be less conservative than accounted for in the appropriate setpoint methodology but is not beyond the Allowable Value, the channel performance is still within the requirements of the plant safety analysis. Under these conditions, the setpoint must be readjusted to be equal to or more conservative than accounted for in the appropriate setpoint methodology.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.6.4.5, SR 3.3.6.4.6, and SR 3.3.6.4.8 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies that 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.

(continued)

CLINTON B 3.3-206 Revision No. 14-2

SPMU System Instrumentation B 3.3.6.4 BASES SURVEILLANCE SR 3.3.6.4.7 REQUIREMENTS (continued) The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic for a specific channel. The system functional testing performed in LCO 3.6.2.4, "Suppression Pool Makeup (SPMU) System,"

overlaps this Surveillance to provide complete testing of the assumed safety function.

The Self Test System may be utilized to perform this testing for those components that it is designed to monitor. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. USAR, Section 7.3.1.1.10

2. USAR, Section 6.2.7.

3. GENE-770-06-1, "Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications,"

February 1991.

CLINTON B 3.3-207 Revision No. 14-2

Relief and LLS Instrumentation B 3.3.6.5 BASES ACTIONS B.l and B.2 (continued)

If the inoperable trip system is not restored to OPERABLE status within 7 days, per Condition A, or if two trip systems are inoperable, then 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 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 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 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 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , provided the associated Function maintains relief or LLS initiation capability, as applicable. 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. This Note is based on the reliability analysis (Ref. 3) assumption of the average time required to perform channel surveillance. That analysis demonstrated the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the relief and LLS valves will initiate when necessary.

SR 3.3.6.5.1 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. 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. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3. 3-212 Revision No. 14-2

Relief and LLS Instrumentation B 3.3.6.5 BASES SURVEILLANCE SR 3.3.6.5.2 (continued)

REQUIREMENTS If the as-left instrument channel setpoint cannot be returned to within the ALT of the Actual Trip Setpoint, then the channel shall be declared inoperable. Part 3 of the Note indicates that the Nominal Trip Setpoint and the methodology used to determine the Nominal Trip Setpoint, the As-Found Tolerance and the As-Left Tolerance bands are specified in the ORM.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.6.5.3 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 SR 3.3.6.5.3 calibration is modified by a Note. This Note is divided into three parts. Part 1 of the Note requires evaluation of instrument performance for the condition where the as-found setting for these instrument channels is outside its As-Found Tolerance (AFT) but conservative with respect to the Allowable Value.

Evaluation of instrument performance will verify that the instrument will continue to behave in accordance with design-basis assumptions. The purpose of the assessment is to ensure confidence in the instrument performance prior to returning the instrument to service. Initial evaluation will be performed by the technician performing the surveillance who will evaluate the instrument's ability to maintain a stable setpoint within the As-Left Tolerance (ALT). The technician's evaluation will be reviewed by on-shift operations personnel during the approval of the surveillance data. Subsequent to returning the instrument to service, the deviation is entered into the Corrective Action Program. In accordance with procedures, entry into the Corrective Action Program will require review and documentation of the condition for operability by on-shift operations personnel. Additional evaluation and potential corrective actions as necessary will ensure that any as-found setting found outside the AFT is evaluated for long-term operability trends. If the as-found channel setpoint is not conservative with respect to the Allowable Value, the channel shall be declared inoperable. Part 2 of the Note requires that the instrument channel setpoint shall be reset to within the ALT of the Actual Trip Setpoint (ATSP) . The ATSP is equivalent to or more conservative than the Nominal (continued)

CLINTON B 3.3-213a Revision No. 14-2

Relief and LLS Instrumentation B 3.3.6.5 BASES SURVEILLANCE SR 3.3.6.5.3 (continued)

REQUIREMENTS Trip Setpoint (NTSP). The NTSP is the limiting value of the sensed process variable at which a trip may be set in accordance with the methodology documented in the ORM.

Therefore, the NTSP is equivalent to the Limiting Safety System Setting (LSSS) required by 10 CFR 50.36, "Technical specifications." The Actual Trip Setpoint is also calculated in accordance with the plant-specific setpoint methodology as documented in the CPS ORM and may include additional margin. The ATSP will ensure that sufficient margin to the safety and/or analytical limit is maintained.

If the as-left instrument channel setpoint cannot be returned to within the ALT of the Actual Trip Setpoint, then the channel shall be declared inoperable. Part 3 of the Note indicates that the Nominal Trip Setpoint and the methodology used to determine the Nominal Trip Setpoint, the As-Found Tolerance and the As-Left Tolerance bands are specified in the ORM.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.6.5.4 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required actuation logic for a specific channel. The system functional testing performed for S/RVs in LCO 3.4.4 and LCO 3.6.1.6 overlaps this Surveillance to provide complete testing of the assumed safety function.

The Self Test System may be utilized to perform this testing for those components that it is designed to monitor. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. USAR, Section 5.2.2.

2. USAR, Section 7.3.1.1.1.4.2.

3. GENE-770-06-1, "Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications,"

February 1991.

CLINTON B 3.3-213b Revision No. 14-2

This page intentionally left blank CLINTON B 3.3-214 Revision No. 14-2

CRV System Instrumentation B 3.3.7.1 BASES ACTIONS B.l and B.2 (continued)

With any Required Action and associated Completion Time not met, one CRV subsystem must be placed in the high radiation mode of operation (Required Action B.l) to ensure that control room personnel will be protected in the event of a Design Basis Accident. The method used to place the CRV subsystem in operation must provide for automatically reinitiating the subsystem upon restoration of power following a loss of power to the CRV subsystem(s).

Alternately, if it is not desired to start the subsystem in the high radiation mode, the CRV subsystem associated with inoperable, untripped channels must be declared inoperable 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 intended to allow the operator time to place the CRV subsystem in operation. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is acceptable because it minimizes risk while allowing time for restoration or tripping of channels, or for placing the associated CRV subsystem in operation.

SURVEILLANCE As noted at the beginning of the SRs, the SRs for each CRV REQUIREMENTS System Instrumentation Function are located in the SRs column of Table 3.3.7.1-1.

The Surveillances are also modified by a Note to indicate that 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 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , provided the associated Function maintains CRV System high radiation mode initiation capability. 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. This Note is based on the reliability analysis (Refs. 4 and 5) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the CRV System will initiate when necessary.

SR 3.3.7.1.1 Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A (continued)

CLINTON B 3.3-219 Revision No. 14-2

CRV System Instrumentation B 3.3.7.1 BASES SURVEILLANCE SR 3.3.7.1.1 (continued)

REQUIREMENTS CHANNEL CHECK is normally a comparison of the indicated parameter for one instrument channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The CHANNEL CHECK supplements less formal, but more frequent, checks of channel status during normal operational use of the displays associated with channels required by the LCO.

SR 3.3.7.1.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. 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. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.7.1.3 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 (continued)

CLINTON B 3.3-220 Revision No. 14-2

CRV System Instrumentation B 3.3.7.1 BASES SURVEILLANCE SR 3.3.7.1.3 (continued)

REQUIREMENTS adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. USAR, Section 7.3.1.1.6.

2. USAR, Section 6.4.

3. USAR, Chapter 15.

4. GENE-770-06-1, "Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications,"

February 1991.

5. NEDC-31677P-A, "Technical Specification Improvement Analysis for BWR Isolation Actuation Instrumentation,"

July 1990.

6. USAR, Section 7.6.1.2.5.

7. USAR, Section 7.6.2.2.5.

CLINTON B 3.3-221 Revision No. 14-2

LOP Instrumentation B 3.3.8.1 BASES ACTIONS B.1 (continued)

If any Required Action and associated Completion Time is not met, the associated Function may not be capable of performing the intended function. Therefore, the associated DG(s) are declared inoperable immediately. This requires entry into applicable Conditions and Required Actions of LCO 3.8.1 and LCO 3.8.2, which provide appropriate actions for the inoperable DG(s).

SURVEILLANCE As noted at the beginning of the SRs, the SRs for each LOP REQUIREMENTS Instrumentation Function-are located in the SRs column of Table 3.3.8.1-1.

The Surveillances are modified by a Note to indicate that 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 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months provided the associated Function maintains DG initiation capability. Upon completion of the Surveillance, or expiration of the 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken.

SR 3.3.8.1.1 This SR has been deleted.

SR 3.3.8.1.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. For series Functions, i.e., for the degraded voltage relays in series with their associated delay timers, a separate CHANNEL FUNCTIONAL TEST is not required for each Function, provided each Function is tested. 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.

Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.3-228 Revision No. 14-2

LOP Instrumentation B 3.3.8.1 BASES SURVEILLANCE SR 3.3.8.1.3 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 Surveillance Frequency-is controlled under the Surveillance Frequency Control Program.

SR 3.3.8.1.4 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required actuation logic for a specific channel. The system functional testing performed in LCO 3.8.1 and LCO 3.8.2 overlaps this Surveillance to provide complete testing of the assumed safety functions.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. USAR, Section 8.3.1.1.2.

2. USAR, Section 5.2.2.

3. USAR, Section 6.3.3.

4. USAR, Chapter 15.

5. IP Calculation 19-AN-19.

CLINTON B 3.3-229 Revision No. 14-2

RPS Electric Power Monitoring B 3.3.8.2 BASES SURVEILLANCE SR 3.3.8.2.1 (continued)

REQUIREMENTS 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. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

As noted in the Surveillance, the CHANNEL FUNCTIONAL TEST is only required to be performed while the plant is in a condition in which the loss of the RPS bus will not jeopardize steady state power operation (the design of the system is such that the power source must be removed from service to conduct the Surveillance). The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The Note in the Surveillance is based on guidance provided in Generic Letter 91-09 (Ref. 3).

SR 3.3.8.2.2 CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies that 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 Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.8.2.3 Performance of a system functional test demonstrates a required system actuation (simulated or actual) signal. The logic of the system will automatically trip open the associated power monitoring assembly circuit breaker. Only one signal per power monitoring assembly is required to be tested. This Surveillance overlaps with the CHANNEL CALIBRATION to provide complete testing of the safety function. The system functional test of the Class 1E circuit breakers is included as part of this test to provide complete testing of the safety function. If the breakers are incapable of operating, the associated electric power monitoring assembly would be inoperable.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.3-235 Revision No. 14-2

RPS Electric Power Monitoring B 3.3.8.2 BASES (continued)

REFERENCES 1. USAR, Section 8.3.1.1.3.1.

2. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.

3 NRC Generic Letter 91-09, "Modification of Surveillance Interval for the Electric Protective Assemblies in Power Supplies for the Reactor Protection System."

CLINTON B 3.3-236 Revision No. 14-2

Recirculation Loops Operating B 3.4.1 BASES ACTIONS D.1 (continued)

With no recirculation loops in operation, or the Required Action and associated Completion Time of Conditions A, B, or C not met, the unit is required to be brought to a MODE in which the LCO does not apply. The plant is required to be placed in MODE 3 in 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . In this condition, the recirculation loops are not required to be operating because of the reduced severity of DBAs and minimal dependence on the recirculation loop coastdown characteristics. The allowed Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 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 3.4.1.1 REQUIREMENTS This SR ensures-the recirculation loop flows are within the allowable limits for mismatch. At low core flow (i.e.,

< 70% of rated core flow), the MCPR requirements provide larger margins to the fuel cladding integrity Safety Limit such that the potential adverse effect of early boiling transition during a LOCA is reduced. A larger flow mismatch can therefore be allowed when core flow is < 70% of rated core flow. The recirculation loop jet pump flow, as used in this Surveillance, is the summation of the flows from all of the jet pumps associated with a single recirculation loop.

The mismatch is measured in terms of percent of rated core flow. This SR is not required when both loops are not in operation since the mismatch limits are meaningless during single loop or natural circulation operation. The Surveillance must be performed within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after both loops are in operation. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to recirculation loop flow values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 4).

(continued)

CLINTON B 3.4-7 Revision No. 14-2

FCVs B 3.4.2 BASES ACTIONS B.1 (continued)

If the FCVs are not deactivated, (locked up) and cannot be restored to OPERABLE status within the associated Completion Time, the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the unit must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . This brings the unit to a condition where the flow coastdown characteristics of the recirculation loop are not important. The allowed Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging unit systems.

SURVEILLANCE SR 3.4.2.1 REQUIREMENTS Hydraulic power unit pilot operated isolation valves located between the servo valves and the common "open" and "close" lines are required to close in the event of a loss of hydraulic pressure. When closed, these valves inhibit FCV motion by blocking hydraulic pressure from the servo valve to the common open and close lines as well as to the alternate subloop. This Surveillance verifies FCV lockup on a loss of hydraulic pressure as assumed in the design basis LOCA analyses.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.4-11 Revision No. 14-2

Jet Pumps B 3.4.3 BASES SURVEILLANCE SR 3.4.3.1 (continued)

REQUIREMENTS Individual jet pumps in. a recirculation loop typically do not have the same flow. The unequal flow is due to the drive flow manifold, which does not distribute flow equally to all risers. The flow (or jet pump diffuser to lower plenum differential pressure) pattern or relationship of one jet pump to the loop average is repeatable. An appreciable change in this relationship is an indication that increased (or reduced) resistance has occurred in one of the jet pumps. This may be indicated by an increase in the relative flow for a jet pump that has experienced beam cracks.

The deviations from normal are considered indicative of a potential problem in the recirculation drive flow or jet pump system (Ref. 2). Normal flow ranges and established jet pump flow and differential pressure patterns are established by plotting historical data as discussed in Reference 2.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by two Notes. Note 1 allows this Surveillance not to be performed until 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after the associated recirculation loop is in operation, since these checks can only be performed during jet pump operation. The 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is an acceptable time to establish conditions appropriate for data collection and evaluation.

Note 2 allows this SR not to be performed when THERMAL POWER is

21.6% RTP. During low flow conditions, jet pump noise approaches the threshold response of the associated flow instrumentation and precludes the collection of repeatable and meaningful data.

With regard to drive flow and differential pressure values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 4).

REFERENCES 1. USAR, Section 6.3.3.

2. GE Service Information Letter No. 330, "Jet Pump Beam Cracks," June 9, 1990.

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

4. Calculation IP-0-0031.

CLINTON B 3.4-16 Revision No. 14-2

S/RVs B 3.4.4 BASES SURVEILLANCE SR 3.4.4.2 (continued)

REQUIREMENTS The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by a Note that excludes valve actuation.

This prevents an RPV pressure blowdown.

SR 3.4.4.3 A manual actuation of each required S/RV (those valves removed and replaced to satisfy SR 3.4.4.1) is performed to verify that the valve is functioning properly. This SR can be demonstrated by one of two methods. If performed by Method 1, plant startup is allowed prior to performing this test because valve OPERABILITY and the setpoints for overpressure protection are verified, per ASME requirements (Ref. 6), prior to valve installation. Therefore, this SR is modified by a Note that states the Surveillance is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reactor steam pressure and flow are adequate to perform the test. The 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowed for manual actuation after the required pressure is reached is sufficient to achieve stable conditions for testing and provides a reasonable time to complete the SR. If performed by Method 2, valve OPERABILITY has been demonstrated for all installed S/RVs based upon the successful operation of a test sample of S/RVs.

1. Manual actuation of the S/RV with verification of the response of the turbine control valves or bypass valves, by a change in the measured steam flow, or any other method suitable to verify steam flow (e.g.,

tailpipe temperature or acoustic monitoring).

Adequate reactor steam pressure must be available to perform this test to avoid damaging the valve. Also, adequate 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 consistent with the pressure recommended by the valve manufacturer.

(continued)

CLINTON B 3.4-21 Revision No. 14-2

S/RVs B 3.4.4 BASES SURVEILLANCE SR 3.4.4.3 (continued)

REQUIREMENTS

2. The sample population of S/RVs tested to satisfy SR 3.4.4.1 will also be stroked in the relief mode during "as-found" testing to verify proper operation of the S/RV. The successful performance of the test sample of S/RVs provides reasonable assurance that the remaining installed S/RVs will perform in a similar fashion. After the S/RVs are replaced, the relief-mode actuator of the newly-installed S/RVs will be uncoupled from the S/RV stem, and cycled to ensure that no damage has occurred to the S/RV during transportation and installation. Following cycling, the relief-mode actuator is recoupled and the proper positioning of the stem nut is independently verified.

This verifies that each replaced S/RV will properly perform its intended function. If the 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 Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

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

2. USAR, Section 5.2.2.

3. USAR, Section 15.

4. NEDC-32202P, "SRV Setpoint Tolerance and Out-of-Service Analysis for Clinton Power Station, "August 1993."

5. Calculation IP-0-0032.

6. ASME/ANSI OM-1987, Operation and Maintenance of Nuclear Power Plants, Part 1.

7. ASME Code for Operation and Maintenance of Nuclear Power Plants.

CLINTON B 3.4-22 Revision No. 14-2

RCS Operational LEAKAGE B 3.4.5 BASES ACTIONS C.l and C.2 (continued) brought to MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 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 3.4.5.1 REQUIREMENTS The RCS LEAKAGE is monitored by a variety of instruments designed to quantify the various types of LEAKAGE. Leakage detection instrumentation is discussed in more detail in the Bases for LCO 3.4.7, "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 7. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to LEAKAGE values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 8).

REFERENCES 1. 10 CFR 50.2.

2. 10 CFR 50.55a(c).

3. 10 CFR 50, Appendix A, GDC 55.

4. GEAP-5620, "Failure Behavior in ASTM A106B Pipes Containing Axial Through-Wall Flaws," April 1968.

5. NUREG-75/067, "Investigation and Evaluation of Cracking in Austenitic Stainless Steel Piping of Boiling Water Reactor Plants," October 1975.

6. USAR, Section 5.2.5.5.3.

7. Regulatory Guide 1.45, May 1973.

8. Calculation IP-0-0033.

CLINTON B 3.4-27 Revision No. 14-2

RCS Leakage Detection Instrumentation B 3.4.7 BASES APPLICABLE and 5). Each of the leakage detection systems inside the SAFETY ANALYSES drywell is designed with the capability of detecting LEAKAGE (continued) less than the established LEAKAGE rate limits.

Identification of the LEAKAGE allows the operators to evaluate the significance of the indicated LEAKAGE and, if 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 (Ref. 6).

Therefore, these actions provide adequate response before a significant break in the RCPB can occur.

RCS leakage detection instrumentation satisfies Criterion 1 of the NRC Policy Statement.

LCO The drywell floor drain sump flow monitoring system is required to quantify the unidentified LEAKAGE from the RCS.

Thus, for the system to be considered OPERABLE, either the sump level rate of change, or the sump pump discharge flow monitoring portion of the system must be OPERABLE. The other monitoring systems provide qualitative indication 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 3.4.5. This Applicability is consistent with that for LCO 3.4.5.

ACTIONS A.1 With both drywell floor drain sump flow monitoring systems inoperable, no other form of sampling can provide the equivalent information to quantify leakage. However, the drywell atmospheric activity monitor and the drywell air cooler condensate flow rate monitor will provide indications of changes in leakage.

With both drywell floor drain sump monitoring systems inoperable, but with RCS unidentified and total LEAKAGE being determined (SR 3.4.5.1), operation may (continued)

CLINTON B 3.4-35 Revision No. 14-2

RCS Leakage Detection Instrumentation B 3.4.7 BASES SURVEILLANCE SR 3.4.7.1 (continued)

REQUIREMENTS gives reasonable confidence that the channel is operating properly. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.4.7.2 This SR requires 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 the desired manner. The test also verifies the relative accuracy of the instrumentation. 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 Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.4.7.3 This SR requires the performance of a CHANNEL CALIBRATION of the required RCS leakage detection instrumentation channels.

The calibration verifies the accuracy of the instrumentation, including the instruments located inside the drywell. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. 10 CFR 50, Appendix A, GDC 30.

2. Regulatory Guide 1.45.

3. USAR, Section 5.2.5.2.2.

4. GEAP-5620, "Failure Behavior in ASTM A106B Pipes Containing Axial Through-Wall Flaws," April 1968.

5. NUREG-75/067, "Investigation and Evaluation of Cracking in Austenitic Stainless Steel Piping of Boiling Water Reactor Plants," October 1975.

6. USAR, Section 5.2.5.5.3.

7. USAR, Section 5.2.5.9.

CLINTON B 3.4-38 Revision No. 14-2

RCS Specific Activity B 3.4.8 BASES (continued)

SURVEILLANCE SR 3.4.8.1 REQUIREMENTS This Surveillance is performed to ensure iodine remains within limit during normal operation. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

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.

With regard to specific activity values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 3).

REFERENCES 1. 10 CFR 100.11.

2. USAR, Section 15.6.4.

3. Calculation IP-0-0035.

CLINTON B 3.4-42 Revision No. 14-2

RHR Shutdown Cooling System-Hot Shutdown B 3.4.9 BASES ACTIONS B.1, B.2, and B.3 (continued)

During the period when the reactor coolant is being circulated by an alternate method (other than by the required RHR shutdown cooling subsystem or recirculation pump), the reactor coolant temperature and pressure must be periodically monitored to ensure proper function of the alternate method. The once per hour Completion Time is deemed appropriate.

SURVEILLANCE SR 3.4.9.1 REQUIREMENTS This Surveillance verifies that one RHR shutdown cooling subsystem or recirculation pump is in operation and circulating reactor coolant. The required flow rate is determined by the flow rate necessary to provide sufficient decay heat removal capability. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This Surveillance is modified by a Note allowing sufficient time to align the RHR System for shutdown cooling operation after clearing the pressure interlock that isolates the system, or for placing a recirculation pump in operation.

The Note takes exception to the requirements of the Surveillance being met (i.e., forced coolant circulation 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. USAR, Section 5.4.7.

CLINTON B 3.4-47 Revision No. 14-2

RHR Shutdown Cooling System-Cold Shutdown B 3.4.10 BASES SURVEILLANCE SR 3.4.10.1 (continued)

REQUIREMENTS decay heat removal capability. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. USAR, Section 5.4.7.

CLINTON B 3.4-52 Revision No. 14-2

RCS P/T Limits B 3.4.11 BASES ACTIONS C.1 and C.2 (continued)

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 > 200'F. Several methods may be used, including comparison with pre-analyzed transients, new analyses, or inspection of the components.

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

SURVEILLANCE SR 3.4.11.1 REQUIREMENTS Verification that operation is within limits is required periodically when RCS pressure and temperature conditions are undergoing planned changes. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

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.

This SR has been modified by a Note that requires this Surveillance to be performed only during system heatup and cooldown operations and inservice leakage and hydrostatic testing.

(continued)

CLINTON B 3.4-58 Revision No. 14-2

RCS P/T Limits B 3.4.11 BASES SURVEILLANCE SR 3.4.11.3 and SR 3.4.11.4 (continued)

REQUIREMENTS (continued) An acceptable means of demonstrating compliance with the temperature differential requirement in SR 3.4.11.4 is to compare the temperatures of the operating recirculation loop and the idle loop.

SR 3.4.11.3 and SR 3.4.11.4 have been modified by a Note that requires the Surveillance to be met only in MODES 1, 2, 3, and 4 during recirculation pump start. In MODE 5, the overall stress on limiting components is lower; therefore, AT limits are not required.

With regard to temperature difference values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Refs. 13, 14).

SR 3.4.11.5, SR 3.4.11.6, and SR 3.4.11.7 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 approaching MODE 4 from MODE 5 and in MODE 4 with RCS 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 before and while tensioning the vessel head bolting studs to ensure that once the head is tensioned the limits are satisfied. SR 3.4.11.5 allows up to 10% of the reactor vessel head bolting studs to be fully tensioned with flange temperatures < 70 OF. This allows the closure flange O-rings to be sealed to support raising reactor water level to assist in warming the flanges. When in MODE 4 with RCS temperature

< 80°F, checks of the flange temperatures are required because of the reduced margin to the limits. When in MODE 4 with RCS temperature

90 0 F, monitoring of the flange temperature is required to ensure the temperatures are within limits.

(continued)

CLINTON B 3.4-60 Revision No. 14-2

RCS P/T Limits B 3.4.11 BASES SURVEILLANCE SR 3.4.11.5, SR 3.4.11.6, and SR 3.4.11.7 (continued)

REQUIREMENTS The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to reactor vessel flange and head flange temperature values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 15).

SR 3.4.11.8 and SR 3.4.11.9 Differential temperatures within the applicable limits ensure that thermal stresses resulting from increases in THERMAL POWER or recirculation loop flow during single recirculation loop operation will not exceed design allowances. Performing the Surveillance within 15 minutes before beginning such an increase in power or flow rate provides adequate assurance that the limits will not be exceeded between the time of the Surveillance and the time of the change in operation.

An acceptable means of demonstrating compliance with the temperature differential requirement in SR 3.4.11.9 is to compare the temperatures of the operating recirculation loop and the idle loop.

Plant specific test data has determined that the bottom head is not subject to temperature stratification with natural circulation at power levels as low as 25% of RTP and with any single loop flow rate greater than or equal to 30% of rated loop flow. Therefore, SR 3.4.11.8 and SR 3.4.11.9 have been modified by a Note that requires the Surveillance to be met only when THERMAL POWER or loop flow is being increased when the above conditions are not met. The Note for SR 3.4.11.9 further limits the requirement for this Surveillance to exclude comparison of the idle loop temperature if the idle loop is isolated from the RPV since the water in the loop cannot be introduced into the remainder of the Reactor Coolant System.

(continued)

CLINTON B 3.4-61 Revision No. 14-2

RCS P/T Limits B 3.4.11 BASES SURVEILLANCE SR 3.4.11.8 and SR 3.4.11.9 (continued)

REQUIREMENTS With regard to temperature difference values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Refs. 16, 17).

REFERENCES 1. 10 CFR 50, Appendix G.

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

3. ASTM E 185-82, "Standard Practice for Conducting Surveillance Tests For Light-Water Cooled Nuclear Power Reactor Vessels."

4. 10 CFR 50, Appendix H.

5. Regulatory Guide 1.99, Revision 2, May 1988.

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

7. NEDO-21778-A, "Transient Pressure Rises Affecting Fracture Toughness Requirements for BWRs," December 1978.

8. USAR, Section 15.4.4.

9. USAR, Section 5.3.

10. Deleted

11. Calculation IP-0-0036.

12. Calculation IP-0-0037.

13. Calculation IP-0-0038.

14. Calculation IP-0-0039.

15. Calculation IP-0-0040.

16. Calculation IP-0-0041.

17. Calculation IP-0-0042.

18. GE-NE-B13-02084-00-01, Rev. 0, "Pressure-Temperature Curves for AmerGen, Clinton Power Station Using the Ki, Methodology," August 2000.

CLINTON B 3.4-62 Revision No. 14-2

Reactor Steam Dome Pressure B 3.4.12 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.12 Reactor Steam Dome Pressure BASES BACKGROUND The reactor steam dome pressure is an assumed value in the determination of compliance with reactor pressure vessel overpressure protection criteria and is also an assumed initial condition of Design Basis Accidents (DBAs) and transients.

APPLICABLE The reactor steam dome pressure of

1045 psig is an SAFETY ANALYSES initial condition of the vessel overpressure protection analysis of Reference 1. This analysis assumes an initial maximum reactor steam dome pressure and evaluates the response of the pressure relief system, primarily the safety/relief valves, during the limiting pressurization transient. The determination of compliance with the overpressure criteria is dependent on the initial reactor steam dome pressure; therefore, the limit on this pressure ensures that the assumptions of the overpressure protection analysis are conserved. Reference 2 also assumes an initial reactor steam dome pressure for the analysis of DBAs and transients used to determine the limits for fuel cladding integrity MCPR (see Bases for LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)") and 1% cladding plastic strain (see Bases for LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)").

Reactor steam dome pressure satisfies the requirements of Criterion 2 of the NRC Policy Statement.

LCO The specified reactor steam dome pressure limit of

< 1045 psig ensures the plant is operated within the assumptions of the vessel overpressure protection analysis.

Operation above the limit may result in a transient response more severe than analyzed.

APPLICABILITY In MODES 1 and 2, the reactor steam dome pressure is required to be less than or equal to the limit. In these MODES, the reactor may be generating significant steam, and events which may challenge the overpressure limits are possible.

In MODES 3, 4, and 5, the limit is'not applicable because the reactor is shut down. In these MODES, the reactor pressure is well below the required limit, and no anticipated events will challenge the overpressure limits.

(continued)

CLINTON B 3.4-63 Revision No. 14-2

Reactor Steam Dome Pressure B 3.4.12 BASES (continued)

ACTIONS A.1 With the reactor steam dome pressure greater than the limit, prompt action should be taken to reduce pressure to below the limit and return the reactor to operation within the bounds of the analyses. The 15 minute Completion Time is reasonable considering the importance of maintaining the pressure within limits. This Completion Time also ensures that the probability of an accident while pressure is greater than the limit is minimal.

B.1 If the reactor steam dome pressure cannot be restored to within the limit 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 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 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 3.4.12.1 REQUIREMENTS Verification that reactor steam dome pressure is

1045 psig ensures that the initial conditions of the vessel overpressure protection analysis are met. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to reactor steam dome pressure values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 3).

REFERENCES 1. USAR, Section 5.2.2.

2. USAR, Section 15.

3. Calculation IP-0-0043.

CLINTON B 3.4-64 Revision No. 14-2

ECCS--Operating B 3.5.1 BASES (continued)

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 HPCS System, LPCS System, and LPCI subsystems full of water ensures that the systems will perform properly, injecting their full capacity into the RCS upon demand. This will also prevent a water hammer following an ECCS initiation signal. One acceptable method of ensuring the lines are full is to vent at the high points. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

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 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 potentially capable of being mispositioned are in the correct position. This SR does not apply to valves that 6annot be inadvertently misaligned, such as check valves.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by a Note that allows LPCI subsystems to be considered OPERABLE during alignment and operation for decay heat removal with reactor steam dome pressure less than the 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. This allows operation in the RHR shutdown cooling mode during MODE 3 if necessary.

(continued)

CLINTON B 3.5-10 Revision No. 14-2

ECCS--Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.3 REQUIREMENTS (continued) Verification that ADS accumulator supply pressure is > 140 psig assures adequate air pressure for reliable ADS operation. The accumulator on each ADS valve provides pneumatic pressure for valve actuation. The designed pneumatic supply pressure requirements for the accumulator are such that, following a failure of the pneumatic supply to the accumulator, at least two valve actuations can occur with the drywell at 70% of design pressure (Ref. 15). 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 140 psig is provided by the Instrument Air System. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to ADS accumulator supply pressure values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is not considered to be a nominal value with respect to instrument uncertainties.

This requires additional margin to be added to the limit to compensate for instrument uncertainties, for implementation in the associated plant procedures (Ref. 17).

SR 3.5.1.4 The performance requirements of the 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 requirements for the ECCS pumps) to verify that the ECCS pumps will develop the flow rates required by the respective analyses. The ECCS pump flow rates ensure that adequate core cooling is provided to satisfy the acceptance criteria of 10 CFR 50.46 (Ref. 10).

The pump flow rates are verified with a pump differential pressure that is sufficient to overcome the RPV pressure expected during a LOCA. The 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 LOCAs. These values may be established during pre-operational testing. The Frequency for this Surveillance is in accordance with the Inservice Testing Program requirements.

(continued)

CLINTON B 3. 5-11 Revision No. 14-2

ECCS--Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.4 (continued)

REQUIREMENTS With regard to pump flow rates and differential pressures values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Refs. 18, 19, 20). Calculations 01HPI5, OlLP16 and OIRH26 determine the margin between actual pump performance capability and the system design requirements and the Analyzed Design Limits as established by SAFER/GESTR. These margins are large enough to account for the instrument indication uncertainties and the lower EDG frequency limit per SR 3.8.1.2 and therefore the specified limit in this SR can be considered to be a nominal value (Refs. 18, 19, 20, 24).

SR 3.5.1.5 The ECCS subsystems are required to actuate automatically to perform their design functions. This Surveillance test verifies that, with a required system initiation signal (actual or simulated), the automatic initiation logic of HPCS, LPCS, 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. This Surveillance also ensures that the HPCS System will automatically restart on an RPV low water level (Level 2) signal received subsequent to an RPV high water level (Level 8) trip and that the suction is automatically transferred from the RCIC storage tank to the suppression pool. The LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.1, "Emergency Core Cooling System (ECCS) Instrumentation," overlaps this Surveillance to provide complete testing of the assumed safety function.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3. 5-12 Revision No. 14-2

ECCS-Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.5 (continued)

REQUIREMENTS This SR is modified by a Note that 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 3.5.1.6 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 3.5.1.7 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 Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by a Note that excludes valve actuation.

This prevents an RPV pressure blowdown.

SR 3.5.1.7 A manual actuation of each required ADS valve (those valves removed and replaced to satisfy SR 3.4.4.1) is performed to verify that the valve is functioning properly. This SR can be demonstrated by one of two methods. If performed by Method 1, plant startup is allowed prior to performing this test because valve OPERABILITY and the setpoints for overpressure protection are verified, per ASME requirements (Ref. 22), prior to valve installation. Therefore, this SR is modified by a Note that states the Surveillance is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reactor steam pressure and flow are adequate to perform the test. The 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowed for manual actuation after the required pressure is reached is sufficient to achieve stable (continued)

CLINTON B 3.5-13 Revision No. 14-2

ECCS-Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.7 (continued)

REQUIREMENTS Conditions for testing and provides a reasonable time to complete the SR. If performed by Method 2, valve OPERABILITY has been demonstrated for all installed ADS valves based upon the successful operations of a test sample of S/RVs.

1. Manual actuation of the ADS valve, with verification of the response of the turbine control valves or bypass valves, by a change in the measured steam flow, or any other method suitable to verify steam flow (e.g.,

tailpipe temperature or acoustic monitoring). Adequate reactor steam 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 test. Adequate pressure at which this test is to be performed is consistent with the pressure recommended by the valve manufacturer.

2. The sample population of S/RVs tested to satisfy SR 3.4.4.1 will also be stroked in the relief mode during "as-found" testing to verify proper operation of the S/RV. The successful performance of the test sample of S/RVs provides reasonable assurance that all ADS valves will perform in a similar fashion. After the S/RVs are replaced, the relief-mode actuator of the newly-installed S/RVs will be uncoupled from the S/RV stem, and cycled to ensure that no damage has occurred to the S/RV during transportation and installation. Following cycl-ing, the relief-mode actuator is recoupled and the proper positioning of the stem nut is independently verified. This verifies that each replaced S/RV will properly perform its intended function.

SR 3.5.1.6 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 Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3. 5-14 Revision No. 14-2

ECCS--Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.8 REQUIREMENTS (continued)

This SR ensures that the ECCS RESPONSE TIMES are within limits for each of the ECCS injection and spray subsystems.

The response time limits (i.e., <42 seconds for the LPCI subsystems, <41 seconds for the LPCS subsystem, and <27 seconds for the HPCS system) are specified in applicable surveillance test procedures. This SR is modified by a Note which identifies that the associated ECCS actuation instrumentation is not required to be response time tested.

This is supported by Reference 16.

Response time testing of the remaining subsystem components is required. However, of the remaining subsystem components, the time for each ECCS pump to reach rated speed is not directly measured in the response time tests. The time(s) for the ECCS pumps to reach rated speed is bounded, in all cases, by the time(s) for the ECCS injection valve(s) to reach the full-open position. Plant-specific calculations show that all ECCS motor start times at rated voltage are less than two seconds. In addition, these calculations show that under degraded voltage conditions, the time to rated speed is less than five seconds.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to ECCS RESPONSE TIME values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 21).

(continued)

CLINTON B 3.5-14a Revision No. 14-2

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

REQUIREMENTS With regard to RCIC storage tank water level values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 2).

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

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 3.5.1.4, and SR 3.5.1.5 are applicable to SR 3.5.2.3, SR 3.5.2.5, and SR 3.5.2.6, respectively.

With regard to pump flow rates and differential pressure values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 3, 4, 5).

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 (continued)

CLINTON B 3.5-20 Revision No. 14-2

ECCS-Shutdown B 3.5.2 BASES SURVEILLANCE SR 3.5.2.4 (continued)

REQUIREMENTS in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

In MODES 4 and 5, the RHR System may operate in the shutdown cooling mode to remove decay heat and sensible heat from the reactor. Therefore, RHR valves that are required for LPCI subsystem operation may be aligned for decay heat removal.

This SR is modified by a Note that allows one LPCI subsystem of the RHR System to be considered OPERABLE for the ECCS function if all the required valves in the LPCI flow path can be manually realigned (remote or local) to allow injection into the RPV and the system is not otherwise inoperable. This will ensure adequate core cooling if an inadvertent vessel draindown should occur.

REFERENCES 1. USAR, Section 6.3.3.

2. Calculation IP-0-0049.

3. Calculations OIHP09/10/11 and IP-C-0042.

4. Calculations OlLP08/11/14 and IP-C-0043.

5. Calculations 01RH19/20/22/26 and IP-C-0041.

CLINTON B 3.5-20a Revision No. 14-2

RCIC System B 3.5.3 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. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

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 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 Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.5-24 Revision No. 14-2

RCIC System B 3.5.3 BASES SURVEILLANCE SR 3.5.3.3 and SR 3.5.3.4 REQUIREMENTS (continued) 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 capability to provide rated flow is tested both at the higher and lower operating ranges of the system.

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. Since the required reactor steam pressure must be available to perform SR 3.5.3.3 and SR 3.5.3.4, sufficient time is allowed after adequate pressure and flow are achieved to perform these SRs. Reactor startup is allowed prior to performing the low pressure Surveillance because the reactor pressure is low and the time 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 test has been satisfactorily completed and there is no indication or reason to believe that RCIC is inoperable. Therefore, these SRs are modified by Notes that state the Surveillances are not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after the reactor steam pressure and flow are adequate to perform the test.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to RCIC steam supply pressure values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 5).

With regard to the measured reactor pressure and flow rate values obtained pursuant to SR 3.5.3.3, as read from plant instrumentation assumed in Reference 5, are considered to be nominal values and therefore do not require compensation for instrument indication uncertainties.

With regard to the measured reactor pressure and flow rate values obtained pursuant to SR 3.5.3.4, the values as read from plant indication instrumentation are not considered to be nominal values with respect to instrument uncertainties. This requires additional margin to be added to the limit to compensate for instrument uncertainties, for implementation in the associated plant procedures (Ref. 5).

(continued)

CLINTON B 3.5-25 Revision No. 14-2

RCIC System B 3.5.3 BASES SURVEILLANCE SR 3.5.3.5 REQUIREMENTS (continued) The RCIC System is required to actuate automatically to perform its design function. This Surveillance verifies that with a required system initiation signal (actual or simulated) the automatic initiation logic of RCIC will cause the system 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. This Surveillance test also ensures that 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) trip and that the suction is automatically transferred from the RCIC storage tank to the suppression pool. The LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.2, "Reactor Core Isolation Cooling (RCIC) System Instrumentation," overlaps this Surveillance to provide complete testing of the assumed safety function.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by a Note 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.

REFERENCES 1. 10 CFR 50, Appendix A, GDC 33.

2. USAR, Section 5.4.6.

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

(NRC), "Recommended Interim Revisions to LCO's for ECCS Components," December 1, 1975.

4. Deleted.

5. Calculation 01RI15.

CLINTON B 3.5-26 Revision No. 14-2

Primary Containment Air Locks B 3.6.1.2 BASES SURVEILLANCE SR 3.6.1.2.1 (continued)

REQUIREMENTS specified in the Primary Containment Leakage Rate Testing Program. Conformance to the Primary Containment Leakage Rate Testing Program requires air lock leakage to be included in determining the overall primary containment leakage rate.

With regard to leakage rate values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 5).

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. 4), 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. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. USAR, Section 3.8.

2. 10 CFR 50, Appendix J, Option B.

3. USAR, Section 6.2.1.

4. USAR, Section 15.7.4.

5 Calculation IP-0-0056.

CLINTON B 3. 6-14 Revision No. 14-2

PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.1 (continued)

REQUIREMENTS capability would be required by SR 3.6.1.3.4 and SR 3.6.1.3.7).

The SR is modified by a Note (Note 2) stating that the SR is not required to be met when the purge valves are open for the stated reasons. The Note states that the 36-inch valves may be opened for pressure control, ALARA or air quality considerations for personnel entry, or for Surveillances or special testing on the purge system that require the valves to be open (e.g., testing of containment and drywell ventilation radiation monitors), provided the 12-inch containment purge and the drywell vent and purge lines are isolated. These primary containment purge valves are capable of closing in the environment following a LOCA.

Therefore, these valves are allowed to be open for limited periods of time. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.6.1.3.2 This SR verifies that each primary containment isolation manual valve and blind flange that is located outside primary containment, drywell, and steam tunnel, 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 primary containment boundary is within design limits. This SR does not require any testing or valve manipulation. Rather, it involves verification that those devices outside primary containment, drywell, and steam tunnel, and capable of being mispositioned, are in the correct position. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

Two Notes are 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 (continued)

CLINTON B 3. 6-22b Revision No. 14-2

PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.6 REQUIREMENTS (continued) Verifying that the full closure isolation time of each MSIV is within the specified limits is required to demonstrate OPERABILITY. The full closure isolation time test ensures that the MSIV will isolate in a time period that does not exceed the times assumed in the DBA analyses. The Frequency of this SR is in accordance with the Inservice Testing Program.

With regard to isolation time values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 10).

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 SR 3.3.6.1.6 overlaps this SR to provide complete testing of the safety function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.6.1.3.8 This SR ensures that the leakage rate of secondary containment bypass leakage paths is less than the specified leakage rate. This provides assurance that the assumptions in the radiological evaluations of References 1, 2, and 3 are met. The leakage rate of each bypass leakage path is assumed to be the maximum pathway leakage (leakage through the worse of the two isolation valves) unless the penetration is isolated by use of one closed and de-activated automatic valve, closed manual valve, or blind flange. In this case, the leakage rate of the isolated bypass leakage path is assumed to be the actual pathway (continued)

CLINTON B 3. 6-26 Revision No. 14-2

PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.11 REQUIREMENTS (continued) This SR ensures that the combined leakage rate of the primary containment feedwater penetrations is less than the specified leakage rate. The leakage rate is based on water as the test medium since these penetrations are designed to be sealed by the FWLCS. The 2 gpm leakage limit has been shown by testing and analysis to bound the condition following a DBA LOCA where, for a limited time, both air and water are postulated to leak through this pathway. The leakage rate of each primary containment feedwater penetration is assumed to be the maximum pathway leakage, i.e., the leakage through the worst of the two isolation valves [either IB21-F032A(B) or 1B21-F065A(B)] in each penetration. This provides assurance that the assumptions in the radiological evaluations of References 1 and 2 are met (Ref. 15).

Dose associated with leakage (both air and water) through the primary containment feedwater penetrations is considered to be in addition to the dose associated with all other secondary containment bypass leakage paths.

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

A Note is added to this SR which states that the primary containment feedwater penetrations are only required to meet this leakage limit in Modes 1, 2, and 3. In other conditions, the Reactor Coolant System is not pressurized and specific primary containment leakage limits are not required.

SR 3.6.1.3.12 This SR requires a demonstration that each instrumentation line excess flow check valve (EFCV) which communicates to the reactor coolant pressure boundary (Ref. 16) is OPERABLE by verifying that the valve activates within the required flow range. For instrument lines connected to reactor coolant pressure boundary, the EFCVs serve as an additional flow restrictor to the orifices that are installed inside the drywell (Ref. 14). The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.6-28a Revision No. 14-2

Primary Containment Pressure B 3.6.1.4 BASES (continued)

SURVEILLANCE SR 3.6.1.4.1 REQUIREMENTS Verifying that primary containment to secondary containment differential pressure is within limits ensures that operation remains within the limits assumed in the primary containment analysis. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to differential pressure values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 4).

REFERENCES 1. USAR, Section 6.2.1.1.4.

2. USAR, Table 6.2-1.

3. USAR, Section 6.2.

4. Calculation IP-0-0066.

CLINTON B 3. 6-31 Revision No. 14-2

Primary Containment Air Temperature B 3.6.1.5 BASES SURVEILLANCE SR 3.6.1.5.1 (continued)

REQUIREMENTS containment analyses. In order to determine the primary containment average air temperature, an arithmetic average is calculated, using measurements taken at locations within the primary containment selected to provide a representative sample of the overall primary containment atmosphere. The arithmetical average must consist of at least one reading from one location per quadrant as described in Ref. 3.

However, all available instruments should be used in determining the arithmetical average.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to containment air temperature values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is not considered to be a nominal value with respect to instrument uncertainties.

This requires additional margin to be added to the limit to compensate for instrument uncertainties, for implementation in the associated plant procedures (Ref. 4).

REFERENCES 1. USAR, Section 6.2.

2. USAR, Table 6.2-4.

3. USAR, Section 7.5.1.4.2.4.

4. Calculation IP-0-0067.

CLINTON B 3. 6-34 Revision No. 14-2

LLS Valves B 3.6.1.6 BASES SURVEILLANCE SR 3.6.1.6.1 (continued)

REQUIREMENTS pressure and flow are achieved to perform this test.

Adequate pressure at which this test is to be performed is consistent with the pressure recommended by the valve manufacturer.

2. The sample population of S/RVs tested to satisfy SR 3.4.4.1 will also be stroked in the relief mode during "as-found" testing to verify proper operation of the S/RV. The successful performance of the test sample of S/RVs provides reasonable assurance that all LLS valves will perform in similar fashion. After the S/RVs are replaced, the relief-mode actuator of the newly-installed S/RVs will be uncoupled from the S/RV stem, and cycled to ensure that no damage has occurred to the S/RV during transportation and installation. Following cycling, the relief-mode actuator is recoupled and the proper positioning of the stem nut is independently verified. This verifies that each replaced S/RV will properly perform its intended function.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.6.1.6.2 The LLS designed S/RVs are required to actuate automatically upon receipt of specific initiation signals. A system functional test is performed to verify that the mechanical portions (i.e., solenoids) of the automatic LLS function operate as designed when initiated either by an actual or simulated automatic initiation signal. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.6.5.4 overlaps this SR to provide complete testing of the safety function.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by a Note that excludes valve actuation.

This prevents a reactor pressure vessel pressure blowdown.

REFERENCES 1. USAR, Section 5.2.2.2.3.

2. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.

3. ASME/ANSI OM-1987, Operation and Maintenance of Nuclear Power Plants, Part 1.

CLINTON B 3.6-38 Revision No. 14-2

RHR Containment Spray System B 3.6.1.7 BASES (continued)

SURVEILLANCE SR 3.6.1.7.1 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. 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 Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

A Note has been added to this SR that allows RHR containment spray subsystems to be considered OPERABLE during alignment to and operation in the RHR shutdown cooling mode when below the RHR cut in permissive pressure in MODE 3, if capable of being manually realigned and not otherwise inoperable. At these low pressures and decay heat levels (the reactor is shut down in MODE 3), a reduced complement of subsystems should provide the required containment pressure mitigation function thereby allowing operation of an RHR shutdown cooling loop when necessary.

SR 3.6.1.7.2 Verifying each RHR pump develops a flow rate Ž 3800 gpm while operating in the suppression pool cooling mode with flow through the associated heat exchanger ensures that pump performance has not degraded below the required flow rate during the cycle. It is tested in the pool cooling mode to demonstrate pump OPERABILITY without spraying down equipment in primary containment. Although this SR is satisfied by running the pump in the suppression pool cooling mode, the test procedures that satisfy this SR include appropriate acceptance criteria to account for the higher pressure requirements resulting from aligning the RHR System in the containment spray mode. The Frequency of this SR is in accordance with the Inservice Testing Program.

(continued)

CLINTON B 3.6-42 Revision No. 14-2

RHR Containment Spray System B 3.6.1.7 BASES SURVEILLANCE SR 3.6.1.7.3 REQUIREMENTS (continued)

This SR verifies that each RHR containment spray subsystem automatic valve actuates to its correct position upon receipt of an actual or simulated automatic actuation signal. Actual spray initiation is not required to meet this SR. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.6.3.5 overlaps this SR to provide complete testing of the safety function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.6.1.7.4 This Surveillance is performed following activities that could result in nozzle blockage to verify that the spray nozzles are not obstructed and that flow will be provided when required. Such activities may include a loss of foreign material control (of if it cannot be assured),

following a major configuration change, or following an inadvertent actuation of containment spray. This Surveillance is normally performed by an air or smoke flow test. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. USAR, Section 6.2.1.1.5.

2. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.

3. ASME Code for Operation and Maintenance of Nuclear Power Plants.

4. USAR, Section 5.4.7 CLINTON B 3.6-43 Revision No. 14-2

FWLCS B 3.6.1.9 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.9 Feedwater Leakage Control System (FWLCS)

BASES BACKGROUND Following a DBA LOCA, the FWLCS supplements the isolation function of primary containment isolation valves (PCIVs) in the feedwater lines which also penetrate the secondary containment. These penetrations are sealed by water form the FWLCS to prevent fission products (post-LOCA containment atmosphere) from leaking past the isolation valves and bypassing the secondary containment after a Design Basis Accident (DBA) loss of coolant accident (LOCA).

The FWLCS consists of two independent, manually initiated subsystems. Each subsystem uses its connected train of the residual heat removal (RHR) system and a header to provide sealing water for pressurizing the feedwater piping either between the inboard and outboard containment isolation check valves or between the outboard containment isolation check valve and the outboard motor-operated gate valve.

APPLICABLE The analyses described in Reference 1 provide the evaluation SAFETY ANALYSES of offsite dose consequences during accident conditions.

The analyses take credit for manually initiating FWLCS within 20 minutes following the initiation of a DBA LOCA (assuming termination of feedwater flow through the feedwater lines), after which secondary containment bypass leakage through the feedwater lines is assumed to continue until the associated piping is filled, which occurs within one hour after initiation of the accident.

The FWLCS satisfies Criterion 3 of the NRC Policy Statement.

LCO Two FWLCS subsystems must be OPERABLE so that in the event of an accident, at least one subsystem is OPERABLE assuming a worst-case single active failure. A FWLCS subsystem is OPERABLE when all necessary components are available to pressurize each feedwater piping section with sufficient water pressure to preclude containment atmosphere leakage (following the time period required to fill and pressurize the feedwater piping sections) when the containment atmosphere is at the maximum peak containment pressure, P.

(continued)

CLINTON B 3.6-45 Revision No. 14-2

FWLCS B 3.6.1.9 BASES (continued)

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 FWLCS is not required to be OPERABLE in MODES 4 and 5 to prevent leakage of radioactive material from primary containment.

ACTIONS A.1 With one FWLCS subsystem inoperable, the inoperable subsystem must be restored to OPERABLE status within 30 days. In this Condition, the remaining OPERABLE FWLCS subsystem is adequate to perform the required leakage control function. The 30-day Completion Time is based on low probability of the occurrence of a DBA LOCA, the amount of time available after the event for operator action to prevent exceeding this limit, the low probability of failure of the OPERABLE FWLCS subsystem, and the availability of the PCIVs.

B.1 With two FWLCS 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, the availability of operator action, and the availability of the PCIVs.

C.1 If the inoperable FWLCS subsystem cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 2) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.

(continued)

CLINTON B 3.6-46 Revision No. 14-2

FWLCS B 3.6.1.9 BASES ACTIONS C.1 (continued)

Required Action C.1 is modified by a Note that prohibits the application of LCO 3.0.4.a. This Note clarifies the intent of the Required Action by indicating that it is not permissible under LCO 3.0.4.a to enter MODE 3 from MODE 4 with the LCO not met. While remaining in MODE 3 presents an acceptable level of risk, it is not the intent of the Required Action to allow entry into, and continue operation in, MODE 3 from MODE 4 in accordance with LCO 3.0.4.a.

However, where allowed, a risk assessment may be performed in accordance with LCO 3.0.4.b. Consideration of the results of this risk assessment is required to determine the acceptability of entering MODE 3 from MODE 4 when this LCO is not met. The allowed Completion Time is 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 A system functional test of each FWLCS subsystem is performed to ensure that each FWLCS subsystem will operate through its operating sequence. This includes verifying automatic positioning of valves and operation of each interlock, and that the necessary check valves open.

Adequacy of the associated RHR pumps to deliver FWLCS flow rates required to meet the assumptions made in the supporting analyses concurrent with other modes was demonstrated during acceptance testing of the system after installation. Periodic verification of the capabilities of the RHR pumps is performed under SR 3.5.1.4.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. USAR, Section 15.6.5.

2. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.

CLINTON B 3.6-47 Revision No. 14-2

Suppression Pool Average Temperature B 3.6.2.1 BASES ACTIONS E.1 and E.2 (continued)

If suppression pool average temperature cannot be maintained

< 120'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 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and the plant must be brought to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 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 without challenging plant systems.

Continued addition of heat to the suppression pool with pool temperature > 120°F could result in exceeding the design basis maximum allowable values for primary containment temperature or pressure.

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

Average temperature is determined by taking an arithmetic average of the functional suppression pool water temperature channels. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. When heat is being added to the suppression pool by testing, however, it is necessary to monitor suppression pool temperature more frequently. Testing that adds heat to the suppression pool excludes RHR pump testing. The 5 minute Frequency during testing is justified by the rates at which testing 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 Frequency is 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.

With regard to the 95'F suppression pool average temperature pursuant to this SR, as read from plant indication instrumentation, this limit is considered a nominal value and therefore does not require compensation for instrument indication uncertainties.

(continued)

CLINTON B 3 .6-52 Revision No. 14-2

Suppression Pool Water Level B 3.6.2.2 BASES ACTIONS B.1 and B.2 (continued)

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 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 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 Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to the suppression pool water minimum level values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is not considered to be a nominal value with respect to instrument uncertainties. This requires additional margin to be added to the limit to compensate for instrument uncertainties, for implementation in the associated plant procedures. The suppression pool maximum water level values are considered to be nominal values and do not require compensation for instrument uncertainties (Ref. 2).

REFERENCES 1. USAR, Section 6.2.

2. Calculation IP-0-0049.

CLINTON B 3.6-55 Revision No. 14-2

RHR Suppression Pool Cooling B 3.6.2.3 BASES (continued)

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 being locked, sealed, or secured.

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 Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3. 6-58a Revision No. 14-2

SPMU System B 3.6.2.4 BASES ACTIONS B.1 (continued)

When upper containment pool water temperature is > 120'F, the heat absorption capacity is inadequate to ensure that the suppression pool heat sink capability matches the safety analysis assumptions. Increased temperature has a relatively smaller impact on heat sink capability.

Therefore, the upper containment pool water temperature must be restored to within limit within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is sufficient to restore the upper containment pool to within the specified temperature limit.

It also takes into account the low probability of an event occurring that would require the SPMU System.

C.1 With one SPMU subsystem inoperable for reasons other than Condition A or B, the inoperable subsystem must be restored to OPERABLE status within 7 days. The 7 day Completion Time is acceptable in light of the redundant SPMU System capabilities afforded by the OPERABLE subsystem and the low probability of a DBA occurring during this period.

D.1 and D.2 If any Required Action and required 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 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 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 3.6.2.4.1 REQUIREMENTS The upper containment pool water level is regularly monitored to ensure that the required limits are satisfied.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.6-63 Revision No. 14-2

SPMU System B 3.6.2.4 BASES SURVEILLANCE SR 3.6.2.4.1 (continued)

REQUIREMENTS A fourth and fifth method (Items d. and e.) may be used to determine that there is sufficient water level combined between the upper containment pool and suppression pool when reactor pressure is less than 235 psig in MODE 3. The water level of the reactor cavity pool portion of the upper containment pool must be greater than el. 824 ft 7 inches, or the suppression pool water level must be greater than 19 ft 9 inches to satisfy this requirement.

With regard to upper containment pool water level values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 4).

SR 3.6.2.4.2 The upper containment pool water temperature is regularly monitored to ensure that the required limit is satisfied.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to the water level values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is not considered to be a nominal value with respect to instrument uncertainties. This requires additional margin to be added to the limit to compensate for instrument uncertainties, for implementation in the associated plant procedures (Ref. 5).

SR 3.6.2.4.3 Verifying the correct alignment for manual, power operated, and automatic valves in the SPMU System 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 valves are verified to be in the correct position prior to being locked, sealed, or secured. 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 Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.6-64 Revision No. 14-2

SPMU System B 3.6.2.4 BASES SURVEILLANCE SR 3.6.2.4.4 REQUIREMENTS (continued) This SR requires a verification that each SPMU subsystem automatic valve actuates to its correct position on receipt of an actual or simulated automatic initiation signal. This includes verification of the correct automatic positioning of the valves and of the operation of each interlock and timer. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.6.4.7 overlaps this SR to provide complete testing of the safety function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by a Note that excludes make up to the suppression pool. Since all active components are testable, makeup to the suppression pool is not required.

REFERENCES 1. USAR, Section 6.2.

2. USAR, Chapter 15.

3. USAR, Section 6.2.7.

4. Calculation IP-0-0074.

5. Calculation IP-0-0075.

6. Calculation IP-M-0662.

CLINTON B 3.6-65 Revision No. 14-2

Primary Containment and Drywell Hydrogen Igniters B 3.6.3.2 BASES SURVEILLANCE SR 3.6.3.2.1 and SR 3.6.3.2.2 REQUIREMENTS These SRs verify that there are no physical problems that could affect the igniter operation. Since the igniters are mechanically passive, they are not subject to mechanical failure. The only credible failures are loss of power or burnout. The verification that each required igniter is energized is performed by circuit current versus voltage measurement.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.6.3.2.2 is modified by a Note that indicates that the Surveillance is not required to be performed until 92 days after four or more igniters in the division are discovered to be inoperable.

With regard to circuit current and voltage values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 4).

(continued)

CLINTON B 3.6-76 Revision No. 14-2

Primary Containment and Drywell Hydrogen Igniters B 3.6.3.2 BASES SURVEILLANCE SR 3.6.3.2.3 and SR 3.6.3.2.4 REQUIREMENTS (continued) These functional tests are performed to verify system OPERABILITY. The current draw to develop a surface temperature of Ž 1700'F is verified for igniters in inaccessible areas, e.g., in a high radiation area.

Additionally, the surface temperature of each accessible igniter is measured to be Ž 1700OF to demonstrate that a temperature sufficient for ignition is achieved. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to current draw and surface temperature values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 4).

REFERENCES 1. 10 CFR 50.44.

2. 10 CFR 50, Appendix A, GDC 41.

3. USAR, Section 6.2.5.

4. Calculation IP-0-0076.

CLINTON B 3.6-77 Revision No. 14-2

Containment/Drywell Hydrogen Mixing System B 3.6.3.3 BASES ACTIONS B.1 and B.2 (continued) reasonable period of time to verify that a loss of hydrogen control function does not exist. The verification 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 Containment/

Drywell Hydrogen Mixing Systems inoperable for up to 7 days.

Seven days is a reasonable time to allow two Containment/

Drywell Hydrogen Mixing Systems 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 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 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 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 3.6.3.3.1 REQUIREMENTS Operating each Containment/Drywell Hydrogen Mixing System ensures that each system is OPERABLE and that all associated controls are functioning properly. It also ensures that blockage, compressor failure, or excessive vibration can be detected for corrective action. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.6-81 Revision No. 14-2

Containment/Drywell Hydrogen Mixing System B 3.6.3.3 BASES SURVEILLANCE SR 3.6.3.3.2 REQUIREMENTS (continued) Verifying that each Containment/Drywell Hydrogen Mixing System flow rate is > 800 scfm ensures that each system is capable of maintaining drywell hydrogen concentrations below the flammability limit. In practice, verifying that the system differential pressure is less than 4.4 psid with the compressor running ensures that the system flow rate is greater than 800 scfm. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to system differential pressure values used to verify the required system flow rate as read from plant indication instrumentation, the procedural limit is considered to be not nominal and therefore requires compensation for instrument indication uncertainties (Ref.

3).

REFERENCES 1. Regulatory Guide 1.7.

2. USAR, Section 6.2.5.

3. Calculation IP-0-0076.

CLINTON B 3. 6-82 Revision No. 14-2

Secondary Containment B 3.6.4.1 BASES ACTIONS C.1 and C.2 (continued) movement of recently 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. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to secondary containment vacuum values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 4).

SR 3.6.4.1.2 and SR 3.6.4.1.3 Verifying that secondary containment equipment hatches and access doors 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. 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, except when the access opening is being used for entry and exit. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.6-88 Revision No. 14-2

Secondary Containment B 3.6.4.1 BASES SURVEILLANCE SR 3.6.4.1.4 and SR 3.6.4.1.5 (continued)

REQUIREMENTS conditions. The primary purpose of these SRs is to ensure secondary containment boundary integrity. The secondary purpose of these SRs 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 for ensuring OPERABILITY of the SGT System. These SRs need not be performed with each SGT subsystem. The inoperability of the SGT System does not necessarily constitute a failure of these Surveillances relative to the secondary containment OPERABILITY. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to drawdown time values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Refs. 5, 6).

REFERENCES 1. USAR, Section 15.6.5.

2. USAR, Section 15.7.4.

3. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.

4. Calculation IP-0-0082.

5. Calculation IP-0-0083.

6. Calculation IP-0-0084.

7. Calculation 3C10-1079-001.

CLINTON B 3.6-88b Revision No. 14-2

SCIDs B 3.6.4.2 BASES SURVEILLANCE SR 3.6.4.2.1 (continued)

REQUIREMENTS The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

Two Notes have been added to this SR. The first Note applies to valves, dampers, 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 SCIDs, once they have been verified to be in the proper position, is low.

A second Note has been included to clarify that SCIDs that are open under administrative controls are not required to meet the SR during the time the SCIDs are open.

SR 3.6.4.2.2 Verifying the isolation time of each power operated and each automatic SCID is within limits is required to demonstrate OPERABILITY. The isolation time test ensures that the SCID will isolate in a time period less than or equal to that assumed in the safety analyses. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to isolation time values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 4).

(continued)

CLINTON B 3.6-94 Revision No. 14-2

SCIDs B 3.6.4.2 BASES SURVEILLANCE SR 3.6.4.2.3 REQUIREMENTS (continued) Verifying that each automatic SCID closes on a secondary containment isolation signal is required to prevent leakage of radioactive material from secondary containment following a DBA or other accident. This SR ensures that each automatic SCID will actuate to the isolation position on a secondary containment isolation signal. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.6.2.5 overlaps this SR to provide complete testing of the safety function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. USAR, Section 15.6.5.

2. USAR, Section 6.2.3.

3. USAR, Section 15.7.4.

4. Calculation IP-0-0085.

CLINTON B 3. 6-95 Revision No. 14-2

SGT System B 3.6.4.3 BASES SURVEILLANCE SR 3.6.4.3.1 REQUIREMENTS Operating each SGT subsystem from the main control room 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 (automatic heater cycling to maintain temperature) for Ž 10 continuous hours eliminates moisture on the adsorbers and HEPA filters.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program..

With regard to operating time values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 10).

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 bypass leakage and efficiency, minimum system flow rate, combined HEPA filter and charcoal adsorber pressure drop, and heater dissipation.

The frequencies for performing the SGT System filter tests are in accordance with Regulatory Guide 1.52 (Ref. 4) and include testing initially, after 720 hours0.00833 days 0.2 hours 0.00119 weeks 2.7396e-4 months of system operation, once per 24 months, and following painting, fire, or chemical release in any ventilation zone communicating with the system. The laboratory test results will be verified to be within limits within 31 days of removal of the sample from the system. Additional information is discussed in detail in the VFTP.

With regard to filter testing values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 11).

(continued)

CLINTON B 3.6-101 Revision No. 14-2

SGT System B 3.6.4.3 BASES SURVEILLANCE SR 3.6.4.3.3 REQUIREMENTS (continued) This SR requires verification that each SGT subsystem automatically starts upon receipt of an actual or simulated initiation signal.

The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.6.2.5 overlaps this SR to provide complete testing of the safety function.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.6.4.3.4 This SR requires verification that the SGT filter cooling bypass damper can be opened and the fan started. This ensures that the ventilation mode of SGT System operation is available. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. 10 CFR 50, Appendix A, GDC 41.

2. USAR, Section 6.2.3.

3. USAR, Section 15.6.5.

4. Regulatory Guide 1.52.

5. USAR, Section 6.5.1.

6. USAR, Section 15.6.4.

7. USAR Appendix A.

8. ASME/ANSI N510-1980.

9. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002

10. Calculation IP-0-0086.

11. Calculation IP-0-0087.

CLINTON B 3.6-101a Revision No. 14-2

Drywell B 3.6.5.1 BASES SURVEILLANCE SR 3.6.5.1.1 (continued)

REQUIREMENTS Surveillance is only required to be performed once within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months after each closing. The Frequency of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is based on operating experience.

With regard to seal leakage values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 3).

SR 3.6.5.1.2 This SR requires a test to be performed to verify overall air lock leakage of the drywell air lock at pressures Ž 3.0 psig. Prior to performance of this test, the air lock must be pressurized to 19.7 psid. This differential pressure is the assumed peak drywell pressure expected from the accident analysis. Since the drywell pressure rapidly returns to a steady state maximum differential pressure of 3.0 psid (due to suppression pool vent clearing), the overall air lock leakage is allowed to be measured at this pressure.

An overall air lock leakage limit of

2 scfh has been established to ensure the integrity of the seals. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR has been modified by a Note indicating that an inoperable air lock door does not invalidate the previous successful performance of an 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.

With regard to air lock leakage values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 3).

(continued)

CLINTON B 3.6-105 Revision No. 14-2

Drywell B 3.6.5.1 BASES SURVEILLANCE SR 3.6.5.1.3 REQUIREMENTS (continued) The analyses in Reference 1 are based on a maximum drywell bypass leakage. This Surveillance ensures that the actual drywell bypass leakage is less than or equal to the acceptable A/j design value of 1.0 ft 2 assumed in the safety analysis. As left drywell bypass leakage, prior to the first startup after performing a required drywell bypass leakage test, is required to be

10% of the drywell bypass leakage limit. At all other times between required drywell leakage rate tests, the acceptance criteria is based on the design A/lU. At the design A/Vikthe containment temperature and pressurization response are bounded by the assumptions of the safety analysis. One drywell air lock door is left open during each drywell bypass leakage test such that each drywell air lock door is leak tested during at least every other drywell bypass leakage test. This ensures that the leakage through the drywell air lock is properly accounted for in the measured bypass leakage and that each air lock door is tested periodically.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. This Frequency is modified by a note that allows for a one-time deferral of this surveillance until November 23, 2008. If during the performance of this required Surveillance the drywell bypass leakage is determined to be greater than the leakage limit, the Surveillance Frequency is increased to at least once every 48 months. If during the performance of the subsequent consecutive Surveillance the drywell bypass leakage is determined to be less than or equal to the drywell bypass leakage limit, the Frequency specified in the Surveillance Frequency Control Program may be resumed. If during the performance of the subsequent consecutive Surveillance the drywell bypass leakage is determined to be greater than the drywell bypass leakage limit, the Surveillance Frequency is increased to at least once every 24 months. The 24-month Frequency must be maintained until the drywell bypass leakage is determined to (continued)

CLINTON B 3. 6-105a Revision No. 14-2

Drywell B 3.6.5.1 BASES SURVEILLANCE SR 3.6.5.1.3 (continued)

REQUIREMENTS be less than or equal to the leakage limit during the performance of two consecutive Surveillances, at which time the Frequency specified in the Surveillance Frequency Control Program may be resumed. For two Surveillances to be considered consecutive, the Surveillances must be performed at least 12 months apart.

With regard to bypass leakage values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 3).

SR 3.6.5.1.4 The exposed accessible drywell interior and exterior surfaces are inspected to ensure there are no apparent physical defects that would prevent the drywell from performing its intended function. This SR ensures that drywell structural integrity is maintained. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. USAR, Chapter 6 and Chapter 15.

2. 10 CFR 50, Appendix J, Option B.

3. Calculation IP-0-0088.

CLINTON B 3. 6-105b Revision No. 14-2

Drywell Air Lock B 3.6.5.2 BASES ACTIONS D.l and D.2 (continued)

If the inoperable drywell air lock 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 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 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 3.6.5.2.1 REQUIREMENTS The air lock door interlock is designed to prevent simultaneous opening of both doors in the air lock. Since both the inner and outer doors of the air lock are designed to withstand the maximum expected post accident drywell pressure, closure of either door will support drywell OPERABILITY. Thus, the door interlock feature supports drywell OPERABILITY while the air lock is being used for personnel transit in and out of the drywell. 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. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3. 6-111 Revision No. 14-2

Drywell Isolation Valves B 3.6.5.3 BASES ACTIONS B.1 (continued)

With one or more drywell vent and purge penetration flow paths with two drywell isolation valves inoperable, 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 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. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is acceptable, due to the low probability of the inoperable valves resulting in excessive drywell leakage and the low probability of the limiting event for drywell leakage occurring during this short time. In addition, the Completion Time is reasonable, considering the time required to isolate the penetration, and the probability of a DBA, which requires the drywell isolation valves to close, occurring during this short time is very low.

Condition B is modified by a Note indicating this Condition is only applicable to drywell vent and purge penetration flow paths. For other penetration flow paths, only one drywell isolation valve is required OPERABLE and, Condition A provides the appropriate Required Actions.

C.1 and C.2 If any Required Action and associated Completion Time cannot be met, the plant must be placed in 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 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 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 3.6.5.3.1 REQUIREMENTS Each 24-inch drywell vent and purge supply isolation valve is required to be periodically verified sealed closed. This Surveillance applies to drywell vent and purge supply isolation valves since they are not qualified to close under accident conditions. This SR is designed to ensure that a gross breach of drywell is not caused by an inadvertent or spurious drywell vent and purge isolation (continued)

CLINTON B 3. 6-118 Revision No. 14-2

Drywell Isolation Valves B 3.6.5.3 BASES SURVEILLANCE SR 3.6.5.3.1 (continued)

REQUIREMENTS valve opening. Detailed analysis of these 24-inch drywell vent and purge supply valves failed to conclusively demonstrate their ability to close during a LOCA in time to support drywell OPERABILITY. Therefore, these valves are required to be in the sealed closed position during MODES 1, 2, and 3. These 24-inch drywell vent and purge supply valves that are sealed closed must be under administrative control to assure that they cannot be inadvertently opened.

Administrative control includes mechanical devices to seal or lock the valve closed, or to prevent power from being supplied to the valve operator. This can be accomplished by removing the air supply to the valve operator or tagging the control switches in the main control room in the closed position. In this application, the term "sealed" has no connotation of leakage within limits. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.6.5.3.2 This SR ensures that the 36-inch and either the 10-inch or the 24-inch drywell vent and purge exhaust isolation valves are closed as required or, if open, open for an allowable reason. These drywell vent and purge isolation valves are fully qualified to close under accident conditions; therefore, these valves are allowed to be open for limited periods of time. This SR has been modified by a Note indicating the SR is not required to be met when the 36-inch and either the 10-inch or the 24-inch drywell vent and purge exhaust valves are open for pressure control, ALARA or air quality considerations for personnel entry, or Surveillances or special testing of the purge system that require the valves to be open (e.g., testing of the containment and drywell ventilation radiation monitors) provided both the 12-inch and 36-inch primary containment purge system supply and exhaust lines are isolated. Normally, the 36-inch drywell vent and purge exhaust isolation valve is open to support operation of the 12-inch Continuous Containment Purge System. This is considered to be within the allowances of the Note. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.6-119 Revision No. 14-2

Drywell Isolation Valves B 3.6.5.3 BASES SURVEILLANCE SR 3.6.5.3.5 REQUIREMENTS (continued) Verifying that each automatic drywell isolation valve closes on a drywell isolation signal is required to prevent bypass leakage from the drywell following a DBA. This SR ensures each automatic drywell isolation valve will actuate to its isolation position on a drywell isolation signal. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.6.1.6 overlaps this SR to provide complete testing of the safety function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. I I REFERENCES 1. USAR, Section 6.2.4.

2. CPS ISI Manual.

3. Calculation IP-0-0091.

CLINTON B 3. 6-121 Revision No. 14-2

Drywell Pressure B 3.6.5.4 BASES ACTIONS B.1 and B.2 (continued) to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 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 3.6.5.4.1 REQUIREMENTS This SR provides assurance that the limitations on drywell-to-primary containment differential pressure stated in the LCO are met. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to drywell-to-primary containment differential pressure values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 6).

REFERENCES 1. USAR, Section 6.2.1.

2. USAR, Section 3.8.

3. USAR, Section 6.2.1.1.6.

4. USAR, Section 6.2.7.

5. USAR, Section 3.8, Attachment A3.8.

6. Calculation IP-0-0092.

CLINTON B 3. 6-124 Revision No. 14-2

Drywell Air Temperature B 3.6.5.5 BASES SURVEILLANCE SR 3.6.5.5.1 (continued)

REQUIREMENTS average must consist of at least one reading from each elevation (with the exception that elevations 729 ft. 0 inches and 732 ft. 0 inches may be considered the same elevation) as described in Ref. 3. However, all available instruments should be used in determining the arithmetical average.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to drywell average air temperature values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is not considered to be a nominal value with respect to instrument uncertainties.

This requires additional margin to be added to the limit to compensate for instrument uncertainties, for implementation in the associated plant procedures (Ref. 4).

REFERENCES 1. USAR, Section 6.2.1.

2. USAR, Section 9.4.7.

3. USAR, Section 7.5.1.4.2.4.

4. Calculation IP-0-0093.

CLINTON B 3.6-127 Revision No. 14-2

Drywell Post-LOCA Vacuum Relief System B 3.6.5.6 BASES ACTIONS D.l and D.2 (continued) the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

E.1 If one drywell post-LOCA vacuum relief subsystem is inoperable for reasons other than Condition A or two or more drywell post-LOCA vacuum relief subsystems are inoperable for reasons other than Condition A, and not restored within the provided Completion Time, the plant must be brought to a condition in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 2) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

Required Action E.1 is modified by a Note that prohibits the application of LCO 3.0.4.a. This Note clarifies the intent of the Required Action by indicating that it is not permissible under LCO 3.0.4.a to enter MODE 3 from MODE 4 with the LCO not met. While remaining in MODE 3 presents an acceptable level of risk, it is not the intent of the Required Action to allow entry into, and continue operation in, MODE 3 from MODE 4 in accordance with LCO 3.0.4.a.

However, where allowed, a risk assessment may be performed in accordance with LCO 3.0.4.b. Consideration of the results of this risk assessment is required to determine the acceptability of entering MODE 3 from MODE 4 when this LCO is not met.

SURVEILLANCE SR 3.6.5.6.1 REQUIREMENTS Each drywell post-LOCA vacuum relief valve is verified to be closed (except when being tested in accordance with SR 3.6.5.6.2 and SR 3.6.5.6.3 or when the drywell post-LOCA vacuum relief valves are performing their intended design function) to ensure that this potential large drywell bypass leakage path is not present. This Surveillance is normally performed by observing the drywell post-LOCA vacuum relief valve position indication. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3. 6-131 Revision No. 14-2

Drywell Post-LOCA Vacuum Relief System B 3.6.5.6 BASES SURVEILLANCE SR 3.6.5.6.1 (continued)

REQUIREMEN Two Notes are added to this SR. The first Note allows drywell post-LOCA vacuum relief valves opened in conjunction with the performance of a Surveillance to not be considered as failing this SR. These periods of opening drywell post-LOCA vacuum relief valves are controlled by plant procedures and do not represent inoperable drywell post-LOCA vacuum relief valves. A second Note is included to clarify that valves open due to an actual differential pressure, are not considered as failing this SR.

SR 3.6.5.6.2 Each drywell post-LOCA vacuum relief valve must be cycled to ensure that it opens adequately to perform its design function and returns to the fully closed position. This provides assurance that the safety analysis assumptions are valid. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.6.5.6.3 Verification of the drywell post-LOCA vacuum relief valve opening differential pressure is necessary to ensure that the safety analysis assumptions of < 0.2 psid for drywell vacuum relief are valid. The safety analysis assumes that the drywell post-LOCA vacuum relief valves will start opening when the dry well pressure is approximately 0.2 psid less than the containment and will be fully open when this differential pressure is 0.5 psid. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. USAR, Section 6.2.

2. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.

CLINTON B 3. 6-132 Revision No. 14-2

Division 1 and 2 SX Subsystems and UHS B 3.7.1 BASES (continued)

SURVEILLANCE SR 3.7.1.1 REQUIREMENTS This SR verifies UHS water volume is Ž 593 acre-feet (excluding sediment). The Surveillance Frequency is in accordance with UHS Erosion, Sediment Monitoring and Dredging Program.

With regard to UHS water volume values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 9).

SR 3.7.1.2 Verifying the correct alignment for each manual, power operated, and automatic valve in each Division 1 and 2 SX subsystem flow path provides assurance that the proper flow paths will exist for Division 1 and 2 SX subsystem 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 and yet considered in the correct position, provided it can be automatically realigned to its accident position within the required 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.

Isolation of the SX subsystem to components or systems does not necessarily affect the OPERABILITY of the associated SX subsystem. As such, when all SX pumps, valves, and piping are OPERABLE, but a branch connection off the main header is isolated, the associated SX subsystem needs to be evaluated to determine if it is still OPERABLE. Alternatively, it is acceptable and conservative to declare an SX subsystem inoperable when a branch connection is isolated or a supported ventilation system is inoperable.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.7-6 Revision No. 14-2

Division 3 SX Subsystem B 3.7.2 BASES SURVEILLANCE SR 3.7.1.3 REQUIREMENTS (continued) This SR verifies that the automatic isolation valves of the Division 1 and 2 SX subsystems will automatically switch to the safety or emergency position to provide cooling water exclusively to the safety related equipment during an accident event. This is demonstrated by use of an actual or simulated initiation signal and is performed with the plant shut down. This SR also verifies the automatic start capability of the SX pump in each subsystem.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. Regulatory Guide 1.27, Revision 2, January 1976.

2. USAR, Section 9.2.1.2.

3. USAR, Table 9.2-3.

4. USAR, Section 6.2.1.1.3.3.

5. USAR, Chapter 15.

6. USAR, Section 6.2.2.3.

7. USAR, Table 6.2-2.

8. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.

9. Calculation IP-0-0095.

CLINTON B 3.7-7 Revision No. 14-2

Division 3 SX Subsystem B 3.7.2 B 3.7 PLANT SYSTEMS B 3.7.2 Division 3 Shutdown Service Water Subsystem (SX)

BASES BACKGROUND The Division 3 SX subsystem is designed to provide cooling water for the removal of heat from components of the Division 3 High Pressure Core Spray (HPCS) System.

The Division 3 SX subsystem consists of one cooling water header (Division 3 subsystem of the SX System), and the associated subsystem pump, piping, and valves. The Ultimate Heat Sink (UHS) is considered part of the SX System (LCO 3.7.1, "Division 1 and 2 Shutdown Service Water (SX)

Subsystems and Ultimate Heat Sink (UHS)").

Cooling water is pumped from a UHS water source by the Division 3 SX pump to the essential components through the Division 3 SX supply header. After removing heat from the components, the water is discharged to the UHS.

The Division 3 SX subsystem specifically supplies cooling water to the Division 3 HPCS diesel generator jacket water coolers and HPCS pump room cooler. The Division 3 SX pump is sized such that it will provide adequate cooling water to the Division 3 equipment required for safe shutdown.

Following a Design Basis Accident or transient, the Division 3 SX subsystem will operate automatically and without operator action as described in the USAR, Section 9.2.1.2 (Ref. 1).

APPLICABLE The ability of the Division 3 SX to provide adequate cooling SAFETY ANALYSES to the HPCS System is an implicit assumption for safety analyses evaluated in the USAR, Chapters 6 and 15 (Refs. 2 and 3, respectively).

The Division 3 SX subsystem satisfies Criterion 3 of the NRC Policy Statement.

LCO The Division 3 SX subsystem is required to be OPERABLE to ensure that the HPCS System will operate as required. An OPERABLE Division 3 SX subsystem consists of an OPERABLE (continued)

CLINTON B 3.7-8 Revision No. 14-2

Division 3 SX Subsystem B 3.7.2 BASES LCO pump; and an OPERABLE Division 3 SX flow path, capable of (continued) taking suction from the UHS source and transferring the water to the appropriate unit equipment.

The OPERABILITY of the Division 1 and 2 SX subsystems and the UHS is discussed is LCO 3.7.1.

APPLICABILITY In MODES 1, 2, and 3, the UHS and Division 3 SX subsystem is required to be OPERABLE to support OPERABILITY of the HPCS System since it is required to be OPERABLE in these MODES.

In MODES 4 and 5, the OPERABILITY requirements of the Division 3 SX subsystem and the UHS are determined by the HPCS System.

ACTIONS A.1 When the Division 3 SX subsystem is inoperable, the capability of the HPCS System to perform its intended function cannot be ensured. Therefore, if the Division 3 SX subsystem is inoperable, the HPCS System must be declared inoperable immediately and the applicable Condition(s) of LCO 3.5.1, "ECCS-Operating," or LCO 3.5.2, "ECCS-Shutdown," entered.

SURVEILLANCE SR 3.7.2.1 REQUIREMENTS Verifying the correct alignment for each required manual, power operated, and automatic valve in the Division 3 SX subsystem flow path provides assurance that the proper flow paths will exist for Division 3 SX subsystem operation.

This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves are verified to be in correct position prior to locking, sealing, or securing.

A valve is also allowed to be in the nonaccident position and yet considered in the correct position, provided it can be automatically realigned to its accident position within the required 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.

(continued)

CLINTON B 3.7-9 Revision No. 14-2

Division 3 SX Subsystem B 3.7.2 BASES SURVEILLANCE SR 3.7.2.1 (continued)

REQUIREMENTS Isolation of the Division 3 SX subsystem to components or systems does not necessarily affect the OPERABILITY of the Division 3 SX subsystem. As such, when the Division 3 SX pump, valves, and piping are OPERABLE, but a branch connection off the main header is isolated, the Division 3 SX subsystem needs to be evaluated to determine if it is still OPERABLE. Alternatively, it is acceptable and conservative to declare an SX subsystem inoperable when a branch connection is isolated or a supported ventilation system is inoperable.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.7.2.2 This SR verifies that the automatic isolation valves of the Division 3 SX subsystem will automatically switch to the safety or emergency position to provide cooling water exclusively to the safety related equipment during an accident event. This is demonstrated by use of an actual or simulated initiation signal and is performed with the plant shut down. This SR also verifies the automatic start capability of the Division 3 SX pump.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. USAR, Section 9.2.1.2.

2. USAR, Chapter 6.

3. USAR, Chapter 15.

CLINTON B 3.7-10 Revision No. 14-2

Control Room Ventilation System B 3.7.3 B 3.7 PLANT SYSTEMS B 3.7.3 Control Room Ventilation System BASES BACKGROUND The Control Room Ventilation System provides a protected environment from which occupants can control the unit following an uncontrolled release of radioactivity, hazardous chemicals or smoke.

The safety related function of the Control Room Ventilation System used to control radiation exposure consists of two independent and redundant high efficiency air filtration subsystems for treatment of recirculated air or outside supply air and a CRE boundary that limits the inleakage of unfiltered air. Each subsystem contains a makeup air filter and a recirculation adsorber, a fan, and the associated ductwork, dampers, doors, barriers, and instrumentation.

The makeup filter consists of a demister, an electric heater, a prefilter, a high efficiency particulate air (HEPA) filter, an activated charcoal adsorber section, and a second HEPA filter. The recirculation adsorber consists of a prefilter and an activated charcoal adsorber section.

Demisters remove water droplets from the airstream.

Prefilters and HEPA filters remove particulate matter that may be radioactive. The charcoal adsorbers provide a holdup period for gaseous iodine, allowing time for decay. For filter train test performed in accordance with ASME/ANSI N510-1980 flow rates are measured with respect to design flow. For the Control Room Ventilation System, the design flows are in scfm.

The CRE is the area within the confines of the CRE boundary that contains the spaces that control room occupants inhabit to control the unit during normal and accident conditions.

This area encompases the control room, and may encompass other non-critical areas to which frequent personnel access or continuous occupancy is not necessary in the event of an accident. The CRE is protected for normal operation, natural events, and accident conditions. The CRE is the combination of walls, floor, roof, ducting, doors, penetrations and equipment that physically form the CRE.

The OPERABILITY of the CRE boundary must be maintained to ensure that the inleakage assumed in the licensing basis analysis of Design basis accident (DBA) consequences to the CRE occupants. The CRE and its boundary are defined in the Control Room Envelope Habitability Program.

In addition to the safety related standby emergency filtration function, parts of the Control Room Ventilation (continued)

CLINTON B 3.7-11 Revision No. 14-2

Control Room Ventilation System B 3.7.3 BASES BACKGROUND System are operated to maintain the CRE environment during (continued) normal operation. Upon receipt of the initiation signal(s)

(indicative of conditions that could result in radiation exposure to CRE occupants), the Control Room Ventilation System automatically switches to the high radiation mode of operation to minimize infiltration of contaminated air into the CRE (outside makeup air is routed through the makeup air filters, the recirculation adsorber is placed in service, and the locker room exhaust is isolated).

The Control Room Ventilation System is designed to maintain a habitable environment in the CRE for a 30 day continuous occupancy after a DBA, without exceeding 5 rem total effective dose equivalent (TEDE) . Control Room Ventilation System operation in maintaining the CRE habitability is discussed in the USAR, Sections 6.5.1 and 9.4.1 (Refs. 1 and 2, respectively).

APPLICABLE The ability of the Control Room Ventilation System to SAFETY ANALYSES maintain the habitability of the CRE is an explicit assumption for the safety analyses presented in the USAR, Chapters 6 and 15 (Refs. 3 and 4, respectively). The high radiation mode of the Control Room Ventilation System is assumed to operate following a DBA. The radiological doses to CRE occupants as a result of the various DBAs are summarized in Reference 4. No single active or passive failure will cause the loss of outside or recirculated air from the CRE.

The Control Room Ventilation System provides protection from smoke and hazardous chemicals to the CRE occupants. The analysis of hazardous chemical releases demonstrates that the toxicity limits are not exceeded in the CRE following a hazardous chemical release (Ref 5). The evaluation of a smoke challenge demonstrates that it will not result in the inability of the CRE occupants to control the reactor either from the control room or from the remote shutdown panels (Ref. 6).

The Control Room Ventilation System satisfies Criterion 3 of the NRC Policy Statement.

(continued)

CLINTON B 3.7-12 Revision No. 14-2

Control Room Ventilation System B 3.7.3 BASES (continued)

LCO Two redundant subsystems of the Control Room Ventilation System are required to be OPERABLE to ensure that at least one is available, if a single active failure disables the other subsystem. Total Control Room Ventilation System failure, such as from a loss of both ventilation subsystems or from an inoperable CRE boundary, could result in exceeding a dose of 5 rem TEDE to the CRE boundary occupants in the event of a DBA.

Each Control Room Ventilation subsystem is considered OPERABLE when the individual components necessary to limit CRE occupant exposure are OPERABLE. A subsystem is considered OPERABLE when its associated:

a. Fan is OPERABLE;

b. HEPA filter and charcoal adsorber are not excessively restricting flow and are capable of performing their filtration functions; and

c. Heater, demister, ductwork, valves, and dampers are OPERABLE, and air circulation can be maintained.

In order for the Control Room Ventilation subsystems to be considered OPERABLE, the CRE boundary must be maintained such that the CRE occupant dose from a large radioactive release does not exceed the calculated dose in the licensing basis consequences analysis for DBAs, and that CRE occupants are protected from hazardous chemicals and smoke.

The LCO is modified by a Note allowing the CRE boundary to be opened intermittently under administrative controls.

This Note only applies to openings in the CRE boundary that can be rapidly restored to the design condition, such as doors, hatches, floor plugs, and access panels. For entry and exit through doors, the administrative control of the opening is performed by the person(s) entering or exiting the area. For other openings, these controls should be proceduralized and consist of stationing a dedicated individual at the opening who is in continuous communication with the operators in the CRE. This individual will have a method to rapidly close the opening and to restore the CRE boundary to a condition equivalent to the design condition when a need for CRE isolation is indicated.

(continued)

CLINTON B 3.7-13 Revision No. 14-2

Control Room Ventilation System B 3.7.3 BASES (continued)

APPLICABILITY In MODES 1, 2, and 3, the Control Room Ventilation System must be OPERABLE to ensure that the CRE will remain habitable during and following a DBA, since the DBA could lead to a fission product release.

In MODES 4 and 5, the probability and consequences of a DBA are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining the Control Room Ventilation System OPERABLE is not required in MODE 4 or 5, except for the following situations under which significant radioactive releases can be postulated:

a. During operations with a potential for draining the reactor vessel (OPDRVs);

b. During CORE ALTERATIONS; and

c. During movement of irradiated fuel assemblies in the primary or secondary containment.

ACTIONS A.1 With one Control Room Ventilation subsystem inoperable for reasons other than an inoperable CRE boundary, the inoperable Control Room Ventilation subsystem must be restored to OPERABLE status within 7 days. With the unit in this condition, the remaining OPERABLE Control Room Ventilation subsystem is adequate to perform the CRE occupant protection function. However, the overall reliability is reduced because a failure in the OPERABLE subsystem could result in loss of Control Room Ventilation System function. The 7 day Completion Time is based on the low probability of a DBA occurring during this time period, and that the remaining subsystem can provide the required capabilities.

B.1 In MODE 1, 2, or 3, if the inoperable Control Room Ventilation subsystem cannot be restored to OPERABLE status within the associated Completion Time, the unit must be placed in a MODE that minimizes overall plant risk. To achieve this status, the unit must be placed in at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 7) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed (continued)

CLINTON B 3.7-14 Revision No. 14-2

Control Room Ventilation System B 3.7.3 BASES ACTIONS B.1 (continued)

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

Required Action B.1 is modified by a Note that prohibits the application of LCO 3.0.4.a. This Note clarifies the intent of the Required Action by indicating that it is not permissible under LCO 3.0.4.a to enter MODE 3 from MODE 4 with the LCO not met. While remaining in MODE 3 presents an acceptable level of risk, it is not the intent of the Required Action to allow entry into, and continue operation in, MODE 3 from MODE 4 in accordance with LCO 3.0.4.a.

However, where allowed, a risk assessment may be performed in accordance with LCO 3.0.4.b. Consideration of the results of this risk assessment is required to determine the acceptability of entering MODE 3 from MODE 4 when this LCO is not met.

C.1, C.2, and C3 If the unfiltered inleakage of potentially contaminated air past the CRE boundary and into the CRE can result in CRE occupant radiological dose greater than the calculated dose of the licensing basis analyses of DBA consequences (allowed to be up to 5 rem TEDE), or inadequate protection of CRE occupants from hazardous chemicals and smoke, the CRE boundary is inoperable. Actions must be taken to restore an OPERABLE CRE boundary within 90 days.

During the period that the CRE boundary is considered inoperable, action must be initiated to implement mitigating actions to lessen the effect on CRE occupants from the potential hazards of a radiological or chemical event or a challenge from smoke. Actions must be taken within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to verify that in the event of a DBA, the mitigating actions will ensure that CRE occupant radiological exposures will not exceed the calculated dose of the licensing basis analyses of DBA consequences, and that CRE occupants are protected from hazardous chemicals and smoke. These mitigating actions (i.e, actions that are taken to offset the consequences of the inoperable CRE boundary) should be preplanned for implementation upon entry into the condition, regardless of whether entry is intentional or unintentional.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is reasonable based on the low probability of a DBA during this time period, and the use of mitigating actions. The 90 day Completion Time is (continued)

CLINTON B 3.7-15 Revision No. 14-2

Control Room Ventilation System B 3.7.3 BASES ACTIONS C.l, C.2, and C3 (continued) reasonable based on the determination that the mitigating actions will ensure protection of CRE occupants within analyzed limits while limiting the probability the CRE occupants will have to implement protective measures that may adversely affect their ability to control the reactor and maintain it in a safe shutdown condition in the event of a DBA. In addition, the 90 day Completion Time is a reasonable time to diagnose, plan and possibly repair, and test most problems with the CRE boundary.

D.1 and D.2 In MODE 1, 2, or 3, if the CRE boundary cannot be restored to OPERABLE status within the required Completion Time, the unit must be placed in a MODE that minimizes accident risk.

To achieve this status, the unit must be placed in at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

E.1, E.2.l, E.2.2, and E.2.3 The Required Actions of Condition E are modified by a Note indicating that LCO 3.0.3 does not apply. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations.

Therefore, inability to suspend movement of irradiated fuel assemblies is not sufficient reason to require a reactor shutdown.

During movement of irradiated fuel assemblies in the primary or secondary containment, during CORE ALTERATIONS, or during OPDRVs, if the inoperable Control Room Ventilation subsystem cannot be restored to OPERABLE status within the required Completion Time, the OPERABLE Control Room Ventilation subsystem may be placed in the high radiation mode. This action ensures that the remaining subsystem is OPERABLE, that no failures that would prevent automatic actuation will occur, and that any active failure will be readily detected.

An alternative to Required Action E.1 is to immediately suspend activities that present a potential for releasing radioactivity that might require the Control Room Ventilation subsystem to be in the high radiation mode of operation. This places the unit in a condition that minimizes the accident risk.

(continued)

CLINTON B 3.7-16 Revision No. 14-2

Control Room Ventilation System B 3.7.3 BASES ACTIONS E.1, E.2.1, E.2.2, and E.2.3 (continued)

If applicable, CORE ALTERATIONS and movement of irradiated fuel assemblies in the primary and secondary containment must be suspended immediately. Suspension of these activities shall not preclude completion of movement of a component to a safe position. Also, if applicable, actions must be initiated immediately to suspend OPDRVs to minimize the probability of a vessel draindown and subsequent potential for fission product release. Actions must continue until the OPDRVs are suspended.

F.1 If both Control Room Ventilation subsystems are inoperable in MODE 1, 2, or 3 for reasons other than an inoperable CRE boundary (i.e., Condition C), the Control Room Ventilation System may not be capable of performing the intended function and the unit is in a condition outside of the accident analyses. Therefore, the plant must be brought to a MODE in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 7) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions is an orderly manner and without challenging plant systems.

Required Action F.1 is modified by a Note that prohibits the application of LCO 3.0.4.a. This Note clarifies the intent of the Required Action by indicating that it is not permissible under LCO 3.0.4.a to enter MODE 3 from MODE 4 with the LCO not met. While remaining in MODE 3 presents an acceptable level of risk, it is not the intent of the Required Action to allow entry into, and continue operation in, MODE 3 from MODE 4 in accordance with LCO 3.0.4.a.

However, where allowed, a risk assessment may be performed in accordance with LCO 3.0.4.b. Consideration of the results of this risk assessment is required to determine the acceptability of entering MODE 3 from MODE 4 when this LCO is not met.

(continued)

CLINTON B 3.7-17 Revision No. 14-2

Control Room Ventilation System B 3.7.3 BASES ACTIONS G.l, G.2, and G.3 (continued)

During movement of irradiated fuel assemblies in the primary or secondary containment, during CORE ALTERATIONS, or during OPDRVs, with two Control Room Ventilation subsystems inoperable or with one or more Control Room Ventilation subsystems inoperable due to an inoperable CRE boundary, action must be taken immediately to suspend activities that present a potential for releasing radioactivity that might require treatment of the control room air. This places the unit in a condition that minimizes the accident risk.

If applicable, CORE ALTERATIONS and movement of irradiated fuel assemblies in the primary and secondary containment must be suspended immediately. Suspension of these activities shall not preclude completion of movement of a component to a safe position. If applicable, actions must be initiated immediately to suspend OPDRVs to minimize the probability of a vessel draindown and subsequent potential for fission product release. Actions must continue until the OPDRVs are suspended.

SURVEILLANCE SR 3.7.3.1 and SR 3.7.3.2 REQUIREMENTS This SR verifies that a subsystem in a standby mode starts on demand and continues to operate. Standby systems should be checked periodically to ensure that they start and function properly. As the environmental and normal operating conditions of this system are not severe, testing each subsystem provides an adequate check on this system.

Periodic heater operation dries out any moisture accumulated in the charcoal from humidity in the ambient air. The Makeup Filter System must be operated from the main control room for Ž 10 continuous hours with the heaters energized.

The Recirculation Filter System (without heaters) need only be operated for Ž 15 minutes to demonstrate the function of the system. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.7-18 Revision No. 14-2

Control Room Ventilation System B 3.7.3 BASES SURVEILLANCE SR 3.7.3.1 and SR 3.7.3.2 (continued)

REQUIREMENTS With regard to subsystem operation time values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 8, 9).

SR 3.7.3.3 This SR verifies that the required Control Room Ventilation System testing is performed in accordance with the Ventilation Filter Testing Program (VFTP). The VFTP includes testing HEPA filter performance, charcoal adsorber bypass leakage and efficiency, minimum system flow rate (scfm), combined HEPA filter and charcoal adsorber pressure drop, and heater dissipation in accordance with Regulatory Guide 1.52 (Ref. 10). The Frequencies for performing the Control Room Ventilation System filter tests are also in accordance with Regulatory Guide 1.52 (Ref.10). Specific test frequencies and additional information are discussed in detail in the VFTP.

SR 3.7.3.4 This SR verifies that each Control Room Ventilation subsystem starts and operates on an actual or simulated high radiation initiation signal. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.7-19 Revision No. 14-2

Control Room Ventilation System B 3.7.3 BASES SURVEILLANCE SR 3.7.3.5 REQUIREMENTS (continued) This SR verifies the OPERABILITY of the CRE boundary by testing for unfiltered air inleakage past the CRE boundary and into the CRE. The details of the testing are specified in the Control Room envelope Habitability Program.

The CRE is considered habitable when the radiological dose to CRE occupants calculated in the licensing basis analyses of DBA consequences is no more than 5 rem TEDE and the CRE occupants are protected from hazardous chemicals and smoke.

This SR verifies that the unfiltered air inleakage into the CRE is no greater than the flow rate assumed in the licensing basis analyses of DBA consequences. When unfiltered air inleakage is greater than the assumed flow rate, Condition C must be entered. Required Action C.3 allows time to restore the CRE boundary to OPERABLE status provided mitigating actions can ensure that the CRE remains within the licensing basis habitability limits for the occupants following an accident. Compensatory measures are discussed in Regulatory Guide 1.196, Section C.2.7.3, (Ref.

11) which endorses, with exceptions, NEI 99-03, Section 8.4 and Appendix F (Ref. 12). These compensatory measures may also be used as mitigating actions as required by Required Action C.2. Temporary analytical methods may also be used as compensatory measures to restore OPERABILITY (Ref. 13).

Options for restoring the CRE boundary to OPERABLE status include changing the licensing basis DBA consequence analysis, repairing the CRE boundary, or a combination of these actions. Depending upon the nature of the problem and the corrective action, a full scope inleakage test may not be necessary to establish that the CRE boundary has been restored to OPERABLE status.

(continued)

CLINTON B 3.7-20 Revision No. 14-2

Control Room Ventilation System B 3.7.3 BASES (continued)

REFERENCES 1. USAR, Section 6.5.1.

2. USAR, Section 9.4.1.

3. USAR, Chapter 6.

4. USAR, Chapter 15.

5. USAR, Section 6.4.

6. USAR, Section 9.5.

7. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002

8. Calculation IP-O-0096.

9. Calculation IP-O-0097.

10. Regulatory Guide 1.52, Revision 2, March 1978.

11. Regulatory Guide 1.196.

12. NEI 99-03, '"Control Room Habitability Assessment,"

June 2001.

13. Letter from Eric J. Leeds (NRC) to James W. Davis (NEI) dated January 10, 2004, "NEI Draft White Paper, Use of Generic Letter 91-18 Process and Alternative Source Terms in the Context of Control Room Habitability." (ADAMS Accession No. ML040300694).

CLINTON B 3.7-21 Revision No. 14-2

Control Room AC System B 3.7.4 B 3.7 PLANT SYSTEMS B 3.7.4 Control Room Air Conditioning (AC) System BASES BACKGROUND The Control Room AC System provides temperature control for the control room.

The Control Room AC System consists of two independent, redundant subsystems that provide cooling, heating, and humidification of recirculated control room air. Each subsystem consists of heating coils, a humidification boiler, cooling coils, fans, chillers, compressors, ductwork, dampers, and instrumentation and controls to provide for control room temperature control.

The Control Room AC System is designed to provide a controlled environment under both normal and accident conditions. The Control Room AC System operation in maintaining the control room temperature is discussed in the USAR, Sections 6.4 and 9.4.1 (Refs. 1 and 2, respectively).

APPLICABLE The design basis of the Control Room AC System is to SAFETY ANALYSES maintain the control room temperature for a 30 day continuous occupancy.

The Control Room AC System components are arranged in redundant safety related subsystems. During emergency operation, the Control Room AC System maintains a habitable environment and ensures the OPERABILITY of components in the control room. A single active failure of a component of the Control Room AC System, assuming a loss of offsite power, does not impair the ability of the system to perform its design function. Redundant detectors and controls are provided for control room temperature control. The Control Room AC System is designed in accordance with Seismic Category I requirements. The Control Room AC System is (continued)

CLINTON B 3.7-22 Revision No. 14-2

Control Room AC System B 3.7.4 BASES APPLICABLE capable of removing sensible and latent heat loads from the SAFETY ANALYSES control room, including consideration of equipment (continued) heat loads and personnel occupancy requirements to ensure equipment OPERABILITY.

The Control Room AC System satisfies Criterion 3 of the NRC Policy Statement.

LCO Two independent and redundant subsystems of the Control Room AC System are required to be OPERABLE to ensure that at least one is available, assuming a single failure disables the other subsystem. Total system failure could result in the equipment operating temperature exceeding limits.

The Control Room AC System is considered OPERABLE when the individual components necessary to maintain the control room temperature are OPERABLE in both subsystems. These components include the cooling coils, fans, chillers, compressors, ductwork, dampers, and associated instrumentation and controls. The heating coils and humidification equipment are not required for Control Room AC System OPERABILITY.

APPLICABILITY In MODE 1, 2, or 3, the Control Room AC System must be OPERABLE to ensure that the control room temperature will not exceed equipment OPERABILITY limits.

In MODES 4 and 5, the probability and consequences of a Design Basis Accident are reducedrdue to the pressure and temperature limitations in these MODES. Therefore, maintaining the Control Room AC System OPERABLE is not required in MODE 4 or 5, except for the following situations under which significant radioactive releases can be postulated:

a. During operations with a potential for draining the reactor vessel (OPDRVs);

b. During CORE ALTERATIONS; and

c. During movement of irradiated fuel assemblies in the primary or secondary containment.

(continued)

CLINTON B 3.7-23 Revision No. 14-2

Control Room AC System B 3.7.4 BASES (continued)

ACTIONS A.l With one control room AC subsystem inoperable, the inoperable control room AC subsystem must be restored to OPERABLE status within 30 days. With the unit in this condition, the remaining OPERABLE control room AC subsystem is adequate to perform the control room air conditioning function. However, the overall reliability is reduced because a single failure in the OPERABLE subsystem could result in loss of the control room air conditioning function. The 30 day Completion Time is based on the low probability of an event occurring requiring Control Room Ventilation System operation in the high radiation mode, the consideration that the remaining subsystem can provide the required protection, and the availability of alternate cooling methods.

B.l and B.2 If both control room AC subsystems are inoperable, the Control Room AC System may not be capable of performing its intended function. Therefore, the control room area temperature is required to be monitored to ensure that temperature is being maintained low enough that equipment in the control room is not adversely affected. With the control room temperature being maintained within the temperature limit, 7 days is allowed to restore a control room AC subsystem to OPERABLE status. This Completion Time is reasonable considering that the control room temperature is being maintained within limits, the low probability of an event occurring requiring control room isolation, and the availability of alternate cooling methods.

C.l In MODE 1, 2, or 3, if the control room area temperature cannot be maintained

86 0 F or if the inoperable control room AC subsystem cannot be restored to OPERABLE status within the associated Completion Time, the unit must be placed in a MODE that minimizes overall plant risk. To achieve this status the unit must be placed in at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref.

3) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.

(continued)

CLINTON B 3.7-24 Revision No. 14-2

Control Room AC System B 3.7.4 BASES (continued)

ACTIONS C.l (continued)

Required Action C.1 is modified by a Note that prohibits the application of LCO 3.0.4.a. This Note clarifies the intent of the Required Action by indicating that it is not permissible under LCO 3.0.4.a to enter MODE 3 from MODE 4 with the LCO not met. While remaining in MODE 3 presents an acceptable level of risk, it is not the intent of the Required Action to allow entry into, and continue operation in, MODE 3 from MODE 4 in accordance with LCO 3.0.4.a.

However, where allowed, a risk assessment may be performed in accordance with LCO 3.0.4.b. Consideration of the results of this risk assessment is required to determine the acceptability of entering MODE 3 from MODE 4 when this LCO is not met. The allowed Completion Time is reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

(continued)

CLINTON B 3.7-25 Revision No. 14-2

Control Room AC System B 3.7.4 BASES ACTIONS D.1, D.2.1, D.2.2, and D.2.3 (continued)

The Required Actions of Condition D are modified by a Note indicating that LCO 3.0.3 does not apply.

If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, inability to suspend movement of irradiated fuel assemblies is not sufficient reason to require a reactor shutdown.

During movement of irradiated fuel assemblies in the primary or secondary containment, during CORE ALTERATIONS, or during OPDRVs, if Required Action A.1 cannot be completed within the required Completion Time, the OPERABLE control room AC subsystem may be placed immediately in operation.

This action ensures that the remaining subsystem is OPERABLE, that no failures that would prevent actuation will occur, and that any active failure will be readily detected.

An alternative to Required Action D.1 is to immediately suspend activities that present a potential for releasing radioactivity that might require operation of the Control Room Ventilation System in the high radiation mode. This places the unit in a condition that minimizes risk.

If applicable, CORE ALTERATIONS and movement of irradiated fuel assemblies in the primary and secondary containment must be suspended immediately. Suspension of these activities shall not preclude completion of movement of a component to a safe position. Also, if applicable, actions must be initiated immediately to suspend OPDRVs to minimize the probability of a vessel draindown and subsequent potential for fission product release. Actions must continue until the OPDRVs are suspended.

E.1, E.2, and E.3 The Required Actions of Condition E.1 are modified by a Note indicating that LCO 3.0.3 does not apply. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations.

Therefore, inability to suspend movement of irradiated fuel assemblies is not sufficient reason to require a reactor shutdown.

(continued)

CLINTON B 3.7-26 Revision No. 14-2

Control Room AC System B 3.7.4 BASES ACTIONS E.1, E.2, and E.3 (continued)

During movement of irradiated fuel assemblies in the primary or secondary containment, during CORE ALTERATIONS, or during OPDRVs, if the Required Action and associated Completion Time of Condition B is not met, action must be taken to immediately suspend activities that present a potential for releasing radioactivity that might require operation of the Control Room Ventilation System in the high radiation mode.

This places the unit in a condition that minimizes risk.

If applicable, CORE ALTERATIONS and handling of irradiated fuel in the primary and secondary containment must be suspended immediately. Suspension of these activities shall not preclude completion of movement of a component to a safe position. Also, if applicable, actions must be initiated immediately to suspend OPDRVs to minimize the probability of a vessel draindown and subsequent potential for fission product release. Actions must continue until the OPDRVs are suspended.

SURVEILLANCE SR 3.7.4.1 REQUIREMENTS This SR verifies that the heat removal capability of the system is sufficient to remove the control room heat load assumed in the safety analysis. The SR consists of a combination of testing and calculation. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to heat removal capability values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 4).

REFERENCES 1. USAR, Section 6.4.

2. USAR, Section 9.4.1.

3. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.

4. Calculation IP-0-0102.

CLINTON B 3.7-27 Revision No. 14-2

Main Condenser Offgas B 3.7.5 B 3.7 PLANT SYSTEMS B 3.7.5 Main Condenser Offgas BASES BACKGROUND During unit operation, steam from the low pressure turbine is exhausted directly into the condenser. Air and noncondensible gases are collected in the condenser, then exhausted through the steam jet air ejectors (SJAEs) to the Main Condenser Offgas System. The offgas from the main condenser normally includes radioactive gases.

The Main Condenser Offgas System has been incorporated into the unit design to reduce the gaseous radwaste emission.

This system uses a catalytic recombiner to recombine radiolytically dissociated hydrogen and oxygen. The gaseous mixture is cooled by the cooler condenser; the water and condensibles are stripped out by the cooler condenser. The radioactivity of the remaining gaseous mixture (i.e., the offgas recombiner effluent) is monitored downstream of the cooler condenser prior to entering the dessicant dryers and charcoal adsorbers.

APPLICABLE The main condenser offgas radioactivity rate is an SAFETY ANALYSES initial condition of the Main Condenser Offgas System failure event as discussed in the USAR, Section 15.7.1 (Ref. 1) . The analysis assumes a gross failure in the Main Condenser Offgas System that results in the rupture of the Main Condenser Offgas System pressure boundary. The radioactivity rate is controlled to ensure that during the event, the calculated offsite doses will be well within the limits (NUREG-0800, Ref. 2) of 10 CFR 100 (Ref. 3), or the NRC staff approved licensing basis.

The main condenser offgas limits satisfy Criterion 2 of the NRC Policy Statement.

LCO To ensure compliance with the assumptions of the Main Condenser Offgas System failure event (Ref. 1), the fission product release rate should be consistent with a noble gas release to the reactor coolant of 100 gCi/MWt-second after decay of 30 minutes. The LCO is conservatively established at 2894 MWt x 100 4Ci/MWt-second = 289 mCi/second.

(continued)

CLINTON B 3 .7-28 Revision No. 14-2

Main Condenser Offgas B 3.7.5 BASES (continued)

APPLICABILITY The LCO is applicable when steam is being exhausted to the main condenser and the resulting noncondensibles are being processed via the Main Condenser Offgas System. This occurs during MODE 1, and during MODES 2 and 3 with any main steam line not isolated and the SJAE in operation. In MODES 4 and 5, steam is not being exhausted to the main condenser and the requirements are not applicable.

ACTIONS A.1 If the offgas radioactivity rate limit is exceeded, 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is allowed to restore the gross gamma activity rate to within the limit. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is reasonable, based on engineering judgment considering the time required to complete the Required Action, the large margins associated with permissible dose and exposure limits, and the low probability of a Main Condenser Offgas System rupture occurring.

B.1, B.2, and B.3 If the radioactivity rate is not restored to within the limits within the associated Completion Time, all main steam lines or the SJAE must be isolated. This isolates the Main Condenser Offgas System from the source of the radioactive steam. The main steam lines are considered isolated if at least one main steam isolation valve in each main steam line is closed, and at least one main steam line drain valve in each drain line is closed. 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 perform the actions from full power conditions in an orderly manner and without challenging unit systems.

An alternative to Required Actions B.1 and B.2 is to place the unit in a MODE in which the overall plant risk is minimized. To achieve this status, the unit must be placed (continued)

CLINTON B 3.7-29 Revision No. 14-2

Main Condenser Offgas B 3.7.5 BASES ACTIONS B.1, B.2, and B.3 (continued) in at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 4) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.

Required Action B.3 is modified by a Note that prohibits the application of LCO 3.0.4.a. This Note clarifies the intent of the Required Action by indicating that it is not permissible under LCO 3.0.4.a to enter MODE 3 from MODE 4 with the LCO not met. While remaining in MODE 3 presents an acceptable level of risk, it is not the intent of the Required Action to allow entry into, and continue operation in, MODE 3 from MODE 4 in accordance with LCO 3.0.4.a.

However, where allowed, a risk assessment may be performed in accordance with LCO 3.0.4.b. Consideration of the results of this risk assessment is required to determine the acceptability of entering MODE 3 from MODE 4 when this LCO is not met. The allowed Completion Time is reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

SURVEILLANCE SR 3.7.5.1 and SR 3.7.5.2 REQUIREMENTS SR 3.7.5.2 requires an isotopic analysis of an offgas sample to ensure that the required limits are satisfied. The noble gases to be sampled are Xe-133, Xe-135, Xe-138, Kr-85m, Kr-87, and Kr-88 (Ref. 5). If the measured release rate of radioactivity increases significantly (by Ž 50% after correcting for expected increases due to changes in THERMAL POWER), an isotopic analysis is also performed within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after the increase is noted, as required by SR 3.7.5.1, to ensure that the increase is not indicative of a sustained increase in the radioactivity rate. The required isotopic analysis is intended to support determination of the cause for the increase in offgas radiation release rates, such as the onset of leakage from a fuel pin(s).

However, there are certain evolutions (e.g., swapping of the steam jet air ejectors and regeneration of the offgas system desiccant dryers) which are known to result in a predictable and (continued)

CLINTON B 3 .7-30 Revision No. 14-2

Main Condenser Offgas B 3.7.5 BASES SURVEILLANCE SR 3.7.5.1 and SR 3.7.5.2 (continued)

REQUIREMENTS temporary increase in the indicated offgas radioactivity release rate. These indicated increases in offgas radioactivity release rates can be caused solely by increases in offgas flow. Since these increases are due to an evolution(s) known to cause such an increase and not due to an actual increase in the "nominal steady state fission gas release rate," isotopic analysis of an offgas sample is not required for these evolutions. In any of these cases, it is prudent to ensure that the offgas radiation level (radioactivity release rate) returns to previous or expected levels within four hours or as soon as possible following the evolution. This will confirm that there are no other causes for the increase in the radioactivity release rate indication. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.7.5.2 is modified by a Note indicating that the SR is not required to be performed until 31 days after any main steam line is not isolated and the SJAE is in operation.

Only in this condition can radioactive fission gases be in the Main Condenser Offgas System at significant rates.

With regard to radioactivity rate values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 6).

REFERENCES 1. USAR, Section 15.7.1.

2. NUREG-0800.

3. 10 CFR 100.

4. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.

5. NEDE-24810, "Station Nuclear Engineering," Volume 1A.

6. Calculation IP-0-0103.

CLINTON B 3.7-31 Revision No. 14-2

Main Turbine Bypass System B 3.7.6 B 3.7 PLANT SYSTEMS B 3.7.6 Main Turbine Bypass System BASES BACKGROUND The Main Turbine Bypass System is designed to control steam pressure when reactor steam generation exceeds turbine requirements during unit startup, sudden load reduction, and cooldown. It allows excess steam flow from the reactor to the condenser without going through the turbine. The bypass capacity of the system is 28.8% of* the Nuclear Steam Supply System rated steam flow. Sudden load reductions within the capacity of the steam bypass can be accommodated without reactor scram. The Main Turbine Bypass System consists of two valve chests (each with three bypass valves) connected to the main steam lines between the main steam isolation valves and the turbine stop valves. Each of the bypass valves is sequentially operated by hydraulic cylinders. The bypass valves are controlled by the pressure regulation function of the Turbine Electro Hydraulic Control System, as discussed in the USAR, Section 7.7.1.5 (Ref. 1). The bypass valves are normally closed, and the pressure regulator controls the turbine control valves, directing all steam flow to the turbine. If the speed governor or the load limiter restricts steam flow to the turbine, the pressure regulator controls the system pressure by opening the bypass valves. When the bypass valves open, the steam flows from the bypass chests, through connecting piping, to the main condenser.

APPLICABLE The Main Turbine Bypass System is assumed to function during SAFETY ANALYSES the design basis feedwater controller failure, maximum demand event, described in the USAR, Section 15.1.2 (Ref. 2). Opening the bypass valves during the pressurization event mitigates the increase in reactor vessel pressure, which affects the MCPR during the event.

The Main Turbine Bypass System satisfies Criterion 3 of the NRC Policy Statement.

LCO The Main Turbine Bypass System is required to be OPERABLE to limit peak pressure in the main steam lines and maintain reactor pressure within acceptable limits during events that cause rapid pressurization, such that the Safety Limit MCPR is not exceeded.

(continued)

CLINTON B 3.7-32 Revision No. 14-2

Main Turbine Bypass System B 3.7.6 BASES LCO An OPERABLE Main Turbine Bypass System requires the bypass (continued) valves to open in response to increasing main steam line pressure. This response is within the assumptions of the applicable analysis (Ref. 2).

APPLICABILITY The Main Turbine Bypass System is required to be OPERABLE at

> 21.6% RTP to ensure that the fuel cladding integrity Safety Limit and the cladding 1% plastic strain limit are not violated during the feedwater controller failure, maximum demand event. As discussed in the Bases for LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)," and LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)," sufficient margin to these limits exists

< 21.6% RTP. Therefore, these requirements are only necessary when operating at or above this power level.

ACTIONS A.1 If the Main Turbine Bypass System is inoperable (one or more bypass valves inoperable), the assumptions of the design basis transient analysis may not be met. Under such circumstances, prompt action should be taken to restore the Main Turbine Bypass System to OPERABLE status. The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is reasonable, based on the time to complete the Required Action and the low probability of an event occurring during this period requiring the Main Turbine Bypass System.

B.1 If the Main Turbine Bypass System cannot be restored to OPERABLE status within the associated Completion Time, THERMAL POWER must be reduced to < 21.6% RTP. As discussed in the Applicability section, operation at < 21.6% RTP results in sufficient margin to the required limits, and the Main Turbine Bypass System is not required to protect fuel integrity during the feedwater controller failure, maximum demand event. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

(continued)

CLINTON B 3.7-33 Revision No. 14-2

Main Turbine Bypass System B 3.7.6 BASES (continued)

SURVEILLANCE SR 3.7.6.1 REQUIREMENTS Cycling each main turbine bypass valve through one complete cycle of full travel demonstrates that the valves are mechanically OPERABLE and will function when required. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.7.6.2 The Main Turbine Bypass System is required to actuate automatically to perform its design function. This SR demonstrates that, with the required system initiation signals, the valves will actuate to their required position.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.7.6.3 This SR ensures that the TURBINE BYPASS SYSTEM RESPONSE TIME is in compliance with the assumptions of the appropriate safety analysis. The response time limits (bypass valve begins to open in

0.1 seconds and 80% of turbine bypass system capacity is established in

0.3 seconds) are specified in applicable surveillance test procedures. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to TURBINE BYPASS SYSTEM RESPONSE TIME values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 3).

REFERENCES 1. USAR, Section 7.7.1.5.

2. USAR, Section 15.1.2.

3. Calculation IP-0-0104.

CLINTON B 3.7-34 Revision No. 14-2

Fuel Pool Water Level B 3.7.7 B 3.7 PLANT SYSTEMS B 3.7.7 Fuel Pool Water Level BASES BACKGROUND The minimum water level in the spent fuel storage pool and upper containment fuel storage pool meets the assumptions of iodine decontamination factors following a fuel handling accident.

A general description of the spent fuel storage pool and upper containment fuel storage pool design is found in the USAR, Section 9.1.2 (Ref. 1) . The assumptions of the fuel handling accident are found in the USAR, Section 15.7.4 (Ref. 2).

APPLICABLE The water level above the irradiated fuel assemblies is an SAFETY ANALYSES explicit assumption of the fuel handling accident. A fuel handling accident is evaluated to ensure that the radiological consequences (calculated whole body and thyroid doses at the exclusion area and low population zone boundaries) are

25% (NUREG-0800, Section 15.7.4, Ref. 3) of the 10 CFR 100 (Ref. 4) exposure guidelines. A fuel handling accident could release a fraction of the fission product inventory by breaching the fuel rod cladding as discussed in the Regulatory Guide 1.25 (Ref. 5).

The fuel handling accident is evaluated for the dropping of an irradiated fuel assembly onto stored fuel bundles. The consequences of a fuel handling accident inside the fuel building and inside containment are documented in Reference 2. The water levels in the spent fuel storage pool and upper containment fuel storage pool provide for absorption of water soluble fission product gases and transport delays of soluble and insoluble gases that must pass through the water before being released to the primary or secondary containment atmosphere, as applicable. This absorption and transport delay reduces the potential radioactivity of the release during a fuel handling accident.

The fuel pool water level satisfies Criterion 2 of the NRC Policy Statement.

(continued)

CLINTON B 3.7-35 Revision No. 14-2

Fuel Pool Water Level B 3.7.7 BASES (continued)

LCO The specified water level preserves the assumption of the fuel handling accident analysis (Ref. 2). As such, it is the minimum required for fuel movement within the spent fuel storage pool and upper containment fuel storage pool.

APPLICABILITY This LCO applies whenever movement of irradiated fuel assemblies occurs in the associated fuel storage racks since the potential for a release of fission products exists.

ACTIONS A.1 Required Action A.1 is modified by a Note indicating that LCO 3.0.3 does not apply. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, inability to suspend movement of irradiated fuel assemblies is not a sufficient reason to require a reactor shutdown.

When the initial conditions for an accident cannot be met, steps should be taken to preclude the accident from occurring. With either fuel pool level less than required, the movement of irradiated fuel assemblies in the associated storage pool is suspended immediately. Suspension of this activity shall not preclude completion of movement of an irradiated fuel assembly to a safe position. This effectively precludes a spent fuel handling accident from occurring in the associated fuel storage pool.

SURVEILLANCE SR 3.7.7.1 REQUIREMENTS This SR verifies that sufficient water is available in the event of a fuel handling accident. The water level in the spent fuel storage pool and upper containment fuel storage pool must be checked periodically. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to fuel pool water level values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 6).

(continued)

CLINTON B 3.7-36 Revision No. 14-2

Fuel Pool Water Level B 3.7.7 BASES (continued)

REFERENCES I1. USAR, Section 9.1.2.

2. USAR, Section 15.7.4.

3. NUREG-0800, Section 15.7.4, Revision 1, July 1981.

4. 10 CFR 100.

5. Regulatory Guide 1.25, March 1972.

6. Calculation IP-0-0105.

CLINTON B 3.7-37 Revision No. 14-2

AC Sources--Operating B 3.8.1 BASES SURVEILLANCE For the Division 1 and 2 DGs, DG operation is returned to REQUIREMENTS the isochronous mode upon switchover such that rated (continued) speed/frequency is automatically attained. For the Division 3 DG, however, with the DG governor initially operating in the droop condition during the test mode, operator action may be required to reset the governor for ready-to-load operation at the required frequency. This difference is acknowledged in the Bases for SR 3.8.1.17 to address compliance with that SR. Notwithstanding, the condition also requires the Division 3 DG to be considered inoperable if it cannot be ensured that the required frequency would be attained in the event of a LOCA and a loss of offsite power concurrent with the Division 3 DG being operated or tested with the existing droop setting in effect. Thus, the Division 3 DG is generally considered inoperable while the droop setting is in effect during the performance of SRs that require the DG to be paralleled to the offsite source.

SR 3.8.1.1 This SR ensures proper circuit continuity for the offsite AC electrical power supply to the onsite distribution network and availability of offsite AC electrical power. The breaker alignment verifies that each breaker is in its correct position to ensure that distribution buses and loads are connected to their preferred power source and that appropriate independence of offsite circuits is maintained.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.8.1.2 and SR 3.8.1.7 These SRs help to ensure the availability of the standby electrical power supply to mitigate DBAs and transients and maintain the unit in a safe shutdown condition.

To minimize the wear on moving parts that do not get lubricated when the engine is not running, these SRs have been modified by Notes (the Note for SR 3.8.1.7 and Note 2 for SR 3.8.1.2) to indicate that all DG starts for these Surveillances may be preceded by an engine prelube period and followed by a warmup period prior to loading.

(continued)

CLINTON B 3.8-13b Revision No. 14-2

AC Sources--Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.2 and SR 3.8.1.7 (continued)

REQUIREMENTS For the purposes of this testing, the DGs are started from standby conditions. Standby conditions mean that the lube oil is heated by the jacket water and continuously circulated through a portion of the system as recommended by the vendor. Engine jacket water is heated by an immersion heater and circulates through the system by natural circulation. This allowance is not intended to impose a maximum limit on engine temperatures. For the purposes of these SRs, the DG may be started using a manual start signal, a simulated loss of offsite power test signal by itself, a simulated loss of offsite power test signal in conjunction with an ECCS actuation test signal, or an ECCS actuation test signal by itself.

In order to reduce stress and wear on diesel engines, the manufacturer recommends that the starting speed of DGs be limited, that warmup be limited to this lower speed, and that DGs be gradually accelerated to synchronous speed prior to loading. These modified start procedures are the intent of Note 3, which is only applicable when such procedures are used.

SR 3.8.1.7 requires that the DG starts from standby conditions and achieves required voltage and frequency within 12 seconds. The 12 second start requirement supports the assumptions in the design basis LOCA analysis (Ref. 5).

The 12 second start requirement may not be applicable to SR 3.8.1.2 (see Note 3 of SR 3.8.1.2), when a modified start procedure as described above is used. If a modified start is not used, the 12 second start requirement of SR 3.8.1.7 applies. Since SR 3.8.1.7 does require a 12 second start, it is more restrictive than SR 3.8.1.2, and it may be performed in lieu of SR 3.8.1.2. This is the intent of Note 1 of SR 3.8.1.2. Similarly, the performance of SR 3.8.1.12 or SR 3.8.1.19 also satisfies the requirements of SR 3.8.1.2 and SR 3.8.1.7.

In addition to the SR requirements, the time for the DG to reach steady state operation, unless the modified DG start method is employed, is periodically monitored and the trend evaluated to identify degradation of governor and voltage regulator performance.

(continued)

CLINTON B 3.8-14 Revision No. 14-2

AC Sources--Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.2 and SR 3.8.1.7 (continued)

REQUIREMENTS The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to required voltage and frequency values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is not considered to be a nominal value with respect to instrument uncertainties.

This requires additional margin to be added to the limit to compensate for instrument uncertainties, for implementation in the associated plant procedures (Refs. 17, 18, 19, 22, 23).

SR 3.8.1.3 This Surveillance demonstrates that the DGs are capable of synchronizing and accepting greater than or equal to the equivalent of the maximum expected accident loads. However, consistent with the recommendations of Regulatory Guide 1.9, Revision 3 (Ref. 16), this surveillance is performed with a DG load equal to or greater than 90 percent of its continuous rating. A minimum run time of 60 minutes is required to stabilize engine temperatures, while minimizing the time that the DG is connected to the offsite source.

Although no power factor requirements are established by this SR, the DG is normally operated at a power factor between 0.8 lagging and 1.0. The 0.8 value is the design rating of the machine, while 1.0 is an operational limitation to ensure circulating currents are minimized.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3. 8-15 Revision No. 14-2

AC Sources--Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.3 (continued)

REQUIREMENTS Note 1 modifies this Surveillance to indicate that diesel engine runs for this Surveillance may include gradual loading, as recommended by the manufacturer, so that mechanical stress and wear on the diesel engine are minimized.

Note 2 modifies this Surveillance by stating that momentary transients because of changing bus loads do not invalidate this test.

Note 3 indicates that this Surveillance shall be conducted on only one DG at a time in order to avoid common cause failures that might result from offsite circuit or grid perturbations.

Note 4 stipulates a prerequisite requirement for performance of this SR. A successful DG start must precede this test to credit satisfactory performance.

With regard to DG loading values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 20).

SR 3.8.1.4 This SR provides verification that the level of fuel oil in the day tank is at or above the low level alarm setpoint.

The level is expressed as an equivalent volume in gallons, and is selected to ensure adequate fuel oil for a minimum of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months of DG operation at maximum expected post LOCA loads.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to fuel oil level values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 21).

(continued)

CLINTON B 3.8-16 Revision No. 14-2

AC Sources--Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.5 REQUIREMENTS (continued) Microbiological fouling is a major cause of fuel oil degradation. There are numerous bacteria that can grow in fuel oil and cause fouling, but all must have a water environment in order to survive. Periodic removal of water from the fuel oil day tanks eliminates the necessary environment for bacterial survival. This is an effective means of controlling microbiological fouling. In addition, it eliminates the potential for water entrainment in the fuel oil during DG operation. Water may come from any of several sources, including condensation, contaminated fuel oil, and breakdown of the fuel oil by bacteria. Frequent checking for and removal of accumulated water minimizes fouling and provides data regarding the watertight integrity of the fuel oil system. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is for preventive maintenance. The presence of water does not necessarily represent a failure of this SR provided that accumulated water is removed during performance of this Surveillance.

SR 3.8.1.6 This Surveillance demonstrates that each required fuel oil transfer pump operates and transfers fuel oil from its associated storage tank to its associated day tank. It is required to support the continuous operation of standby power sources. This Surveillance provides assurance that the fuel oil transfer pump is OPERABLE, the fuel oil piping system is intact, the fuel delivery piping is not obstructed, and the controls and control systems for automatic fuel transfer systems are OPERABLE.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.8.1.7 See SR 3.8.1.2.

(continued)

CLINTON B 3.8-17 Revision No. 14-2

AC Sources--Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.8 REQUIREMENTS (continued) Transfer of each 4.16 kV ESF bus power supply from the normal offsite circuit to the alternate offsite circuit demonstrates the OPERABILITY of the alternate circuit. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by a Note. The reason for the Note is that, during operation with the reactor critical, performance of this SR could cause perturbations to the electrical distribution systems that could challenge continued steady state operation and, as a result, plant safety systems. Credit may be taken for unplanned events that satisfy this SR. Examples of unplanned events may include:

1) Unexpected operational events which cause the equipment to perform the function specified by this surveillance, for which adequate documentation of the required performance is available; and

2) Post maintenance testing that requires performance of this Surveillance in order to restore the component to OPERABLE, provided the maintenance was required, or performed in conjunction with maintenance required to maintain OPERABILITY or reliability.

SR 3.8.1.9 Each DG is provided with an engine overspeed trip to prevent damage to the engine. Recovery from the transient caused by the loss of a large load could cause diesel engine overspeed, which, if excessive, might result in a trip of the engine. This Surveillance demonstrates the DG load response characteristics and capability to reject a load equivalent to at least as large as the largest single load while maintaining a specified margin to the overspeed trip.

(continued)

CLINTON B 3.8-18 Revision No. 14-2

AC Sources--Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.9 (continued)

REQUIREMENTS The referenced load for DG 1A is the low pressure core spray pump; for DG lB, the residual heat removal (RHR) pump; and for DG 1C the HPCS pump. The Shutdown Service Water (SX) pump values are not used as the largest load since the SX supplies cooling to the associated DG. If this load were to trip, it would result in the loss of the DG. The use of larger loads for reference purposes is acceptable. This Surveillance may be accomplished by:

1) Tripping the DG output breaker with the DG carrying greater than or equal to its associated single largest load while paralleled to offsite power, or while supplying the bus, or

2) Tripping its associated single largest load with the DG supplying the bus.

As required by IEEE-308 (Ref. 14), the load rejection test is acceptable if the increase in diesel speed does not exceed 75% of the difference between synchronous speed and the overspeed trip setpoint, or 15% above synchronous speed, whichever is lower.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR has been modified by two Notes. The intent of Note 1 is to indicate that credit may be taken for unplanned events that satisfy this SR. Examples of unplanned events may include:

1) Unexpected operational events which cause the equipment to perform the function specified by this Surveillance, for which adequate documentation of the required performance is available; and (continued)

CLINTON B 3.8-19 Revision No. 14-2

AC Sources--Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.10 (continued)

REQUIREMENTS While the DG is not expected to experience this transient during an event and continue to be available, this response ensures that the DG is not degraded for future application, including reconnection to the bus if the trip initiator can be' corrected or isolated.

In order to ensure that the DG is tested under load conditions that are as close to design basis conditions as possible, testing must be performed using a power factor

< 0.9. This power factor is chosen to be representative of the actual design basis inductive loading that the DG would experience.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR has been modified by a Note. The intent of the Note is to indicate that credit may be taken for unplanned events that satisfy this SR. Examples of unplanned events may include:

1) Unexpected operational events which cause the equipment to perform the function specified by this Surveillance, for which adequate documentation of the required performance is available; and

2) Post maintenance testing that requires performance of this Surveillance in order to restore the component to OPERABLE, provided the maintenance was required, or performed in conjunction with maintenance required to maintain OPERABILITY or reliability.

Testing performed for this SR is normally conducted with the DG being tested (and the associated safety-related distribution subsystem) connected to one offsite source, while the remaining safety-related (and non-safety related) distribution systems are aligned to the other offsite source (or unit auxiliary transformers). This minimizes the possibility of common cause failure resulting from offsite/grid voltage perturbations.

This Surveillance should be conducted on only one DG at a time in order to avoid common cause failures that might result from offsite of grid perturbations.

With regard to DG load and voltage values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 24).

(continued)

CLINTON B 3.8-19b Revision No. 14-2

AC Sources--Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.11 (continued)

REQUIREMENTS full flow, or RHR systems performing a decay heat removal function are not desired to be realigned to the ECCS mode of operation. In lieu of actual demonstration of the connection and loading of these loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by two Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions. Standby conditions mean that the lube oil is heated by the jacket water and continuously circulated through a portion of the system as recommended by the vendor. Engine jacket water is heated by an immersion heater and circulates through the system by natural circulation. This allowance is not intended to impose a maximum limit on engine temperatures. The reason for Note 2 is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge plant safety systems.

Credit may be taken for unplanned events that satisfy this SR. Examples of unplanned events may include:

1) Unexpected operational events which cause the equipment to perform the function specified by this Surveillance, for which adequate documentation of the required performance is available; and

2) Post maintenance testing that requires performance of this Surveillance in order to restore the component to OPERABLE, provided the maintenance was required, or performed in conjunction with maintenance required to maintain OPERABILITY or reliability.

(continued)

CLINTON B 3.8-21 Revision No. 14-2

AC Sources--Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.12 REQUIREMENTS (continued) This Surveillance demonstrates that the DG automatically starts and achieves the required voltage and frequency within the specified time (12 seconds) from the design basis actuation signal (LOCA signal) and operates for Ž 5 minutes.

The 5 minute period provides sufficient time to demonstrate stability.

With regard to DG start time, required voltage and frequency values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is not considered to be a nominal value with respect to instrument uncertainties. This requires additional margin to be added to the limit to compensate for instrument uncertainties, for implementation in the associated plant procedures (Refs. 17, 18, 19, 22, 23).

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by two Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions. Standby conditions mean that the lube oil is heated by the jacket water and continuously circulated through a portion of the system as recommended by the vendor. Engine jacket water is heated by an immersion heater and circulates through the system by natural circulation. This allowance is not intended to impose a maximum limit on engine temperatures. The reason for Note 2 is that during operation with the reactor critical, performance of this SR could cause perturbations to the electrical distribution systems that could challenge continued steady state operation and, as a result, plant safety systems. Credit may be taken for unplanned events that satisfy this SR. Examples of unplanned events may include:

(continued)

CLINTON B 3.8-22 Revision No. 14-2

AC Sources--Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.12 (continued)

REQUIREMENTS

1) Unexpected operational events which cause the equipment to perform the function specified by this Surveillance, for which adequate documentation of the required performance is available; and

2) Post maintenance testing that requires performance of this Surveillance in order to restore the component to OPERABLE, provided the maintenance was required, or performed in conjunction with maintenance required to maintain OPERABILITY or reliability.

SR 3.8.1.13 This Surveillance demonstrates that DG non-critical protective functions (e.g., high jacket water temperature) are bypassed on an ECCS initiation test signal and critical protective functions trip the DG to avert substantial damage to the DG unit. The non-critical trips are bypassed during DBAs and provide alarms on abnormal engine conditions.

These alarms provide the operator with necessary information to react appropriately. The DG availability to mitigate the DBA is more critical than protecting the engine against minor problems that are not immediately detrimental to emergency operation of the DG.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

The SR is modified by a Note. The intent of the Note is to indicate that credit may be taken for unplanned events that satisfy this SR. Examples of unplanned events may include:

1) Unexpected operational events which cause the equipment to perform the function specified by this Surveillance, for which adequate documentation of the required performance is available; and (continued)

CLINTON B 3.8-23 Revision No. 14-2

AC Sources--Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.13 (continued)

REQUIREMENTS

2) Post maintenance testing that requires performance of this Surveillance in order to restore the component to OPERABLE, provided the maintenance was required, or performed in conjunction with maintenance required to maintain OPERABILITY or reliability.

SR 3.8.1.14 Regulatory Guide 1.9, Revision 3 (Ref. 16) requires demonstration that the DGs can start and run continuously at or near full-load capability for an interval of not less than 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The DGs are to be loaded equal to or greater than 105 percent of the continuous rating for at least 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months and equal to or greater than 90 percent of the continuous rating for the remaining hours of the test (i.e.,

22 hours2.546296e-4 days 0.00611 hours 3.637566e-5 weeks 8.371e-6 months ) (Ref. 16). The DG starts for this Surveillance can be performed either from standby or hot conditions. The provisions for prelube and warmup, discussed in SR 3.8.1.2, and for gradual loading, discussed in SR 3.8.1.3, are applicable to this SR.

In order to ensure that the DG is tested under load conditions that are as close to design conditions as possible, testing must be performed using a power factor

< 0.9. This power factor is chosen to be representative of the actual design basis inductive loading that the DG could experience.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This Surveillance is modified by two Notes. Note 1 states that momentary transients due to changing bus loads do not invalidate this test. Similarly, momentary power factor transients above the limit do not invalidate the test. The intent of Note 2 is to indicate that credit may be taken for unplanned events that satisfy this SR. Examples of unplanned events may include:

(continued)

CLINTON B 3.8-24 Revision No. 14-2

AC Sources--Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.14 (continued)

REQUIREMENTS

1) Unexpected operational events which cause the equipment to perform the function specified by this Surveillance, for which adequate documentation of the required performance is available; and

2) Post maintenance testing that requires performance of this Surveillance in order to restore the component to OPERABLE, provided the maintenance was required, or performed in conjunction with maintenance required to maintain OPERABILITY or reliability.

Testing performed for this SR is normally conducted with the DG being tested (and the associated safety-related distribution subsystem) connected to one offsite source, while the remaining safety-related (and non-safety related) distribution systems are aligned to the other offsite source (or unit auxiliary transformers). This minimizes the possibility of common cause failures resulting from offsite/grid voltage perturbations.

With regard to DG loading capability values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 20).

SR 3.8.1.15 This Surveillance is consistent with the recommendations of Regulatory Guide 1.108 (Ref. 10), paragraph 2.a. (5), and demonstrates that the diesel engine can restart from a hot condition, such as subsequent to shutdown from normal Surveillances, and achieve the required voltage and frequency within 12 seconds. The 12 second time is derived from the requirements of the accident analysis to respond to a design basis large break LOCA.

With regard to DG loading values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 20).

With regard to DG start time, frequency and voltage values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is not considered to be a nominal value with respect to instrument uncertainties. This requires additional margin to be added to the limit to compensate for instrument uncertainties, for implementation in the associated plant procedures (Refs. 17, 18, 19, 22, 23).

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.8-25 Revision No. 14-2

AC Sources--Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.15 (continued)

REQUIREMENTS This SR has been modified by two Notes. Note 1 ensures that the test is performed with the diesel sufficiently hot. The requirement that the diesel has operated for at least 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months at full load conditions (i.e., equal to or greater than 90 percent of the continuous rating) prior to performance of this Surveillance is based on manufacturer recommendations for achieving hot conditions. Momentary transients due to changing bus loads do not invalidate this test. Note 2 allows all DG starts to be preceded by an engine prelube period to minimize wear and tear on the diesel during testing.

SR 3.8.1.16 As required by Regulatory Guide 1.108 (Ref. 10),

paragraph 2.a. (6), this Surveillance ensures that the manual synchronization and load transfer from the DG to each offsite power source can be made and that the DG can be returned to ready-to-load status when offsite power is restored. It also ensures that the undervoltage logic is reset to allow the DG to reload if a subsequent loss of offsite power occurs. The DG is considered to be in ready-to-load status when the DG is at rated speed and voltage, the output breaker is open and can receive an auto-close signal on bus undervoltage, and the load sequence timers are reset.

Portions of the synchronization circuit are associated with the DG and portions with the offsite circuit. If a failure in the synchronization requirement of the Surveillance occurs, depending on the specific affected portion of the synchronization circuit, either the DG or the associated offsite circuit is declared inoperable.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.8-26 Revision No. 14-2

AC Sources--Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.17 (continued)

REQUIREMENTS ready-to-load operation in order to complete the surveillance for the Division 3 DG. Resetting the governor ensures that the DG will supply the Division 3 bus at the required frequency in the event of a LOCA and a loss of offsite power while the DG is in a droop condition during the test mode.

The requirement to automatically energize the emergency loads with offsite power is essentially identical to that of SR 3.8.1.12. The intent in the requirement associated with SR 3.8.1.17.b is to show that the emergency loading is not affected by the DG operation in test mode. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the emergency loads to perform these functions is acceptable.

This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR has been modified by a Note. The intent of this note is to indicate that credit may be taken for unplanned events that satisfy this SR. Examples of unplanned events may include:

1) Unexpected operational events which cause the equipment to perform the function specified by this Surveillance, for which adequate documentation of the required performance is available; and

2) Post maintenance testing that requires performance of this Surveillance in order to restore the component to OPERABLE, provided the maintenance was required, or performed in conjunction with maintenance required to maintain OPERABILITY or reliability.

Testing performed for this SR is normally conducted with the DG being tested (and the associated safety-related distribution subsystem) connected to one offsite source, while the remaining safety-related (and non-safety related) distribution systems are aligned to the other offsite source (or unit auxiliary transformers). This minimizes the possibility of common cause failures resulting from offsite/grid voltage perturbations.

(continued)

CLINTON B 3.8-28 Revision No. 14-2

AC Sources--Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.18 REQUIREMENTS (continued) Under accident conditions with a loss of offsite power, loads are sequentially connected to the bus by the load sequencing logic (except for Division 3 which has no load sequence timers). The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading of the DGs due to high motor starting currents.

The 10% load sequence time tolerance ensures that sufficient time exists for the DG to restore frequency and voltage prior to applying the next load and that safety analysis assumptions regarding ESF equipment time delays are not violated and is consistent with the recommendations of Regulatory Guide 1.108 (Ref. 10), paragraph 2.a.(2).

Reference 2 provides a summary of the automatic loading of ESF buses.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by a Note. The reason for the Note is that performing the Surveillance during these MODES may perturb the electrical distribution system, and challenge plant safety systems. Credit may be taken for unplanned events that satisfy this SR. Examples of unplanned events may include:

1) Unexpected operational events which cause the equipment to perform the function specified by this Surveillance, for which adequate documentation of the required performance is available; and

2) Post maintenance testing that requires performance of this Surveillance in order to restore the component to OPERABLE, provided the maintenance was required, or performed in conjunction with maintenance required to maintain OPERABILITY or reliability.

With regard to sequence time values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 25).

(continued)

CLINTON B 3.8-29 Revision No. 14-2

AC Sources--Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.19 REQUIREMENTS (continued) In the event of a DBA coincident with a loss of offsite power, the DGs are required to supply the necessary power to ESF systems so that the fuel, RCS, and containment design limits are not exceeded.

This Surveillance demonstrates the DG operation, as discussed in the Bases for SR 3.8.1.11, during a loss of offsite power actuation test signal in conjunction with an ECCS initiation signal. For load shedding effected via shunt trips that are actuated in response to a LOCA signal (i.e., "ECCS initiation signal"), this surveillance includes verification of the shunt trips (for Divisions 1 and 2 only) in response to LOCA signals originating in the ECCS initiation logic as well as the Containment and Reactor Vessel Isolation and Control System actuation logic. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by two Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions. Standby conditions mean that the lube oil is heated by the jacket water and continuously circulated through a portion of the system as recommended by the vendor. Engine jacket water is heated by an immersion heater and circulates through the system by natural circulation. This allowance is not intended to impose a maximum limit on engine temperatures. The reason for Note 2 is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge plant safety systems.

Credit may be taken for unplanned events that satisfy this SR. Examples of unplanned events may include:

(continued)

CLINTON B 3.8-30 Revision No. 14-2

AC Sources--Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.19 (continued)

REQUIREMENTS

1) Unexpected operational events which cause the equipment to perform the function specified by this Surveillance, for which adequate documentation of the required performance is available; and

2) Post maintenance testing that requires performance of this Surveillance in order to restore the component to OPERABLE, provided the maintenance was required, or performed in conjunction with maintenance required to maintain OPERABILITY or reliability.

With regard to DG start time, required voltage and frequency values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is not considered to be a nominal value with respect to instrument uncertainties. This requires additional margin to be added to the limit to compensate for instrument uncertainties, for implementation in the associated plant procedures (Refs. 17, 18, 19, 22).

SR 3.8.1.20 This Surveillance is performed with the plant shut down and demonstrates that the DG starting independence has not been compromised. Also, this Surveillance demonstrates that each engine can achieve proper speed within the specified time when the DGs are started simultaneously.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by a Note. The reason for the Note is to minimize wear on the DG during testing. For the purpose of this testing, the DGs must be started from standby conditions. Standby conditions mean that the lube oil is heated by the jacket water and continuously circulated through a portion of the system as recommended by the vendor. Engine jacket water is heated by an immersion heater and circulates through the system by natural circulation. This allowance is not intended to impose a maximum limit on engine temperatures.

With regard to required voltage and frequency values obtained pursuant to this SR, as read from plant indication (continued)

CLINTON B 3. 8-31 Revision No. 14-2

AC Sources--Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.20 (continued)

REQUIREMENTS instrumentation, the specified limit is not considered to be a nominal value with respect to instrument uncertainties.

This requires additional margin to be added to the limit to compensate for instrument uncertainties, for implementation in the associated plant procedures (Refs. 17, 18, 19, 22, 23).

(continued)

CLINTON B 3.8-32 Revision No. 14-2

Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 BASES SURVEILLANCE SR 3.8.3.1 (continued)

REQUIREMENTS The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to fuel oil inventory values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 11).

SR 3.8.3.2 This Surveillance ensures that sufficient lube oil inventory is available to support at least 7 days of maximum expected post LOCA load operation for each DG. This minimum volume requirement is based on the DG manufacturer's consumption values for the run time of the DG. Implicit in this SR is the requirement to verify the capability to transfer the lube oil from its storage location to the DG when the DG lube oil sump does not hold adequate inventory for 7 days of maximum expected post LOCA load operation without the level reaching the manufacturer's recommended minimum level.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to lube oil inventory values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 8).

SR 3.8.3.3 The tests of fuel oil prior to addition to the storage tanks are a means of determining whether new fuel oil is of the appropriate grade and has not been contaminated with substances that would have an immediate detrimental impact on diesel engine combustion and operation. If results from these tests are within acceptable limits, the fuel oil may be added to the storage tanks without concern for contaminating the entire volume of fuel oil in the storage tanks. These tests are to be conducted prior to adding the new fuel to the storage tank(s), but in no case is the time between the sample (and corresponding results) of new fuel and addition of new fuel oil to the storage tanks to exceed 31 days. The limits and applicable ASTM Standards for the (continued)

CLINTON B 3.8-45 Revision No. 14-2

Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 BASES SURVEILLANCE SR 3.8.3.3 (continued)

REQUIREMENTS Fuel oil degradation during long term storage shows up as an increase in particulate, mostly due to oxidation. The presence of particulate does not mean that the fuel oil will not burn properly in a diesel engine. However, the particulate can cause fouling of filters and fuel oil injection equipment, which can cause engine failure.

Particulate concentrations should be determined in accordance with ASTM D6217-98(Ref. 6). This method involves a gravimetric determination of total particulate concentration in the fuel oil and has a limit of 10 mg/l.

It is acceptable to obtain a field sample for subsequent laboratory testing in lieu of field testing.

The Frequency of this Surveillance takes into consideration fuel oil degradation trends indicating that particulate concentration is unlikely to change between Frequency intervals.

With regard to fuel oil property values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 9).

SR 3.8.3.4 This Surveillance ensures that, without the aid of the refill compressor, sufficient air start capacity for each DG is available. The system design provides for multiple start attempts without recharging when pressurized above the low pressure alarm setpoint. The pressure specified in this SR reflects a value at which multiple starts can be accomplished, but is not so high as to result in failing the limit due to normal cycling of the recharge compressor.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.8-47 Revision No. 14-2

Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 BASES SURVEILLANCE SR 3.8.3.4 (continued)

REQUIREMENTS With regard to air start capacity values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 10).

SR 3.8.3.5 Microbiological fouling is a major cause of fuel oil degradation. There are numerous bacteria that can grow in fuel oil and cause fouling, but all must have a water environment in order to survive. Periodic removal of water from the storage tanks eliminates the necessary environment for bacterial survival. This is the most effective means of controlling microbiological fouling. In addition, it eliminates the potential for water entrainment in the fuel oil during DG operation. Water may come from any of several sources, including condensation, contaminated fuel oil, and from breakdown of the fuel oil by bacteria.

Frequent checking for and removal of accumulated water minimizes fouling and provides data regarding the watertight integrity of the fuel oil system. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. This SR is for preventive maintenance.

The presence of water does not necessarily represent a failure of this SR provided that accumulated water is removed during performance of the Surveillance.

REFERENCES 1. USAR, Section 9.5.4.

2. Regulatory Guide 1.137.

3. ANSI N195, Appendix B, 1976.

4. USAR, Chapter 6.

5. USAR, Chapter 15.

6. ASTM Standards: D4057-95; D1298-99; D975-06b; D4176-93; D6217-98.

7. Deleted.

8. Calculation IP-0-0120.

9. Calculation IP-0-0121.

10. Calculation IP-0-0122.

11. Calculation IP-C-0111.

CLINTON B 3.8-48 Revision No. 14-2

DC Sources--Operating B 3.8.4 BASES (continued)

SURVEILLANCE SR 3.8.4.1 REQUIREMENTS Verifying battery terminal voltage while on float charge helps to ensure the effectiveness of the battery chargers, which support the ability of the batteries to perform their intended function. Float charge is the condition in which the charger is supplying the continuous charge required to overcome the internal losses of a battery (or battery cell) and maintain the battery in a fully charged state while supplying the continuous steady state loads of the associated DC subsystem. On float charge, battery cells will receive adequate current to continually charge the battery. The voltage requirements are based on the nominal design voltage of the battery and are consistent with the minimum float voltage established by the battery manufacturer (2.20 Vpc or 127.6 V at the battery terminals).

This voltage maintains the battery plates in a condition that supports maintaining the grid life (expected to be approximately 20 years). The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to battery terminal voltage values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 13).

SR 3.8.4.2 This SR verifies the design capacity of the battery chargers. According to Regulatory Guide 1.32 (Ref. 10), the battery charger supply is recommended to be based on the largest combined demands of the various steady state loads and the charging capacity to restore the battery from the design minimum charge state to the fully charged state, irrespective of the status of the unit during these demand occurrences. The minimum required amperes and duration ensure that these requirements can be satisfied. This SR provides two options. One option requires that each battery charger be capable of supplying 300 amps for Divisions 1 and 2 (100 amps for Divisions 3 and 4) at the minimum established float voltage for 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The ampere requirements are based on the output rating of the chargers.

The voltage requirements are based on the charger voltage level after a response to a loss of AC power. The time period is sufficient for the charger temperature to have stabilized and to have been maintained for at least 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

The other option requires that each battery charger be capable of recharging the battery after a service test coincident with supplying the largest coincident demands of the various continuous steady state loads (irrespective or the status of the plant during which these demands occur).

(continued)

CLINTON B 3.8-56 Revision No. 14-2

DC Sources--Operating B 3.8.4 BASES SURVEILLANCE SR 3.8.4.2 (continued)

REQUIREMENTS This level of loading may not normally be available following the battery service test and will need to be supplemented with additional loads. The duration for this test may be longer than the charger sizing criteria since the battery recharge is affected by float voltage, temperature, and the exponential decay in charging current.

The battery is recharged when the measured charging current is < 2 amps.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program..

With regard to minimum required amperes and duration values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 13).

SR 3.8.4.3 A battery service test is a special test of the battery's capability, as found, to satisfy the design requirements (battery duty cycle) of the DC electrical power system. The discharge rate and test length are established with a dummy load that corresponds to the design duty cycle requirements as specified in Reference 4.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by two Notes. Note 1 allows the performance of a modified performance discharge test SR 3.8.6.6 in lieu of SR 3.8.4.3. This substitution is acceptable because SR 3.8.6.6 represents an equivalent test of battery capability as SR 3.8.4.3. The reason for Note 2 is that performing the Surveillance would remove a required DC electrical power subsystem from service, perturb the electrical distribution system, and challenge safety systems. Credit may be taken for unplanned events that satisfy the Surveillance. Examples of unplanned events may include:

(continued)

CLINTON B 3.8-57 Revision No. 14-2

Battery Parameters B 3.8.6 BASES ACTIONS (continued) E.l Batteries in redundant trains with battery parameters not within limits, there is not sufficient assurance that battery capacity has not been affected to the degree that the batteries can still perform their required function, given that redundant batteries are involved. With redundant batteries involved, this potential could result in a total loss of function on multiple systems that rely upon the batteries. The longer completion times specified for battery parameters on non-redundant batteries not within limits are therefore not appropriate, and the parameters must be restored to within limits on at least one train within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

F.1 When any battery parameter is outside the allowances of the Required Actions for Condition A, B, C, D, or E, sufficient capacity to supply the maximum expected load requirement is not assured and the corresponding battery must be declared inoperable. Additionally, discovering a battery in one train with one or more battery cells float voltage less than 2.07 V and float current greater tan 2 amps, indicates that the battery capacity may not be sufficient to perform the intended functions. The battery must therefore be declared inoperable immediately.

SURVEILLANCE SR 3.8.6.1 REQUIREMENTS Verifying battery float current while on float charge is used to determine the state of charge of the battery. Float charge is the condition in which the charger is supplying the continuous charge required to overcome the internal losses of a battery and maintain the battery in a charged state. The float current requirements are based on the float current indicative of a charged battery. Use of float current to determine the state of charge of the battery is consistent with IEEE Standard 450-1995 (Ref. 3). The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by a Note that states the float current requirement is not required to be met when battery terminal voltage is less than the minimum established float voltage of SR 3.8.4.1. When this float voltage is not maintained, the Required Actions of LCO 3.8.4, ACTION A, are being taken, which provide the necessary and appropriate verifications of the battery condition. Furthermore, the float current limit of 2 amps is established based on the nominal float voltage value and is not directly applicable when this voltage is not maintained.

(continued)

CLINTON B 3.8-68 Revision No. 14-2

Battery Parameters B 3.8.6 BASES SURVEILLANCE SR 3.8.6.2 and 3.8.6.5 REQUIREMENTS (continued) Optimal long-term battery performance is obtained by maintaining a float voltage greater than or equal to the minimum established design limits provided by the battery manufacturer, which corresponds to 127.6 V at the battery terminals, or 2.20 Vpc. This provides adequate overpotential, which limits the formation of lead sulfate and self discharge, which could eventually render the battery inoperable. Float voltage, in this range or less, but greater than 2.07 Vpc, are addressed in Specification 5.5.14. SRs 3.8.6.2 and 3.8.6.5 require verification that the cell float voltages are equal to or greater than the short-term absolute minimum voltage of 2.07 V. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.8.6.3 The limit specified for electrolyte level ensures that the plates suffer no physical damage and maintains adequate electron transfer capability. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.8.6.4 This surveillance verifies that the pilot cell temperature is greater than or equal to the minimum established design limit (i.e., 65 degrees F). Pilot cell electrolyte temperature is maintained above this temperature to assure the battery can provide the required current and voltage to meet the design requirements. Temperatures lower than assumed in battery sizing calculations act to inhibit or reduce battery capacity. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.8.6.6 A battery performance test is a test of constant current capacity of a battery, normally done in the as-found condition, after having been in service, to detect any change in the capacity determined by the acceptance test.

The test is intended to determine overall battery degradation due to age and usage.

The acceptance criteria for this Surveillance is consistent with IEEE Standard 450-1995 (Ref. 3) and IEEE Standard 485 (Ref. 5). These references recommend that the battery be replaced if its capacity is below 80% of the manufacturer's rating. A capacity of 80% shows that the battery rate of deterioration is increasing, even there is ample capacity to meet the load requirements. Furthermore, the battery is (continued)

CLINTON B 3.8-68a Revision No. 14-2

Battery Parameters B 3.8.6 BASES SURVEILLANCE SR 3.8.6.6 (continued)

REQUIREMENTS sized to meet the assumed duty cycle loads when the battery design capacity reaches this 80% limit.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. If the battery shows degradation, or if the battery has reached 85% of its expected life, the Surveillance Frequency is reduced to 12 months. Degradation is indicated, according to IEEE Standard 450 (Ref. 3), when the battery capacity drops by more than 10% relative to its capacity on the previous performance test or when it is > 10% below the manufacturer's rating. These Frequencies are based on the recommendations in IEEE Standard 450 (Ref. 3).

This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required DC electrical power subsystem from service, perturb the electrical distribution system, and challenge safety systems. Credit may be taken for unplanned events that satisfy the Surveillance. Examples of unplanned events may include:

1) Unexpected operational events which cause the equipment to perform the function specified by this Surveillance, for which adequate documentation of the required performance is available; and

2) Post maintenance testing that requires performance of this Surveillance in order to restore the component to OPERABLE, provided the maintenance was required, or performed in conjunction with maintenance required to maintain OPERABILITY or reliability.

REFERENCES 1. USAR, Chapter 6.

2. USAR, Chapter 15.

3. IEEE Standard 450, 1995.

4. Calculation IP-0-0123.

5. IEEE Standard 485, 1983

6. USAR, Chapter 8.

CLINTON B 3.8-68b Revision No. 14-2

Inverters--Operating B 3.8.7 BASES ACTIONS F.1 and F.2 (continued)

If the inoperable devices or components 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 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 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 3.8.7.1 REQUIREMENTS This Surveillance verifies that the inverters are functioning properly with all required circuit breakers closed and uninterruptible AC buses energized from the inverter. The verification of proper voltage and frequency output ensures that the required power is readily available for the instrumentation connected to the uninterruptible AC buses. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to voltage and frequency values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 5).

REFERENCES 1. USAR, Chapter 8.

2. USAR, Chapter 6.

3. USAR, Chapter 15.

4. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.

5. Calculation IP-0-0131.

CLINTON B 3.8-73 Revision No. 14-2

Inverters- Shutdown B 3.8.8 BASES ACTIONS A.1, A.2.1, A.2.2, A.2.3, and A.2. (continued) completed as quickly as possible in order to minimize the time the plant safety systems may be without power or powered from a constant voltage source transformer.

SURVEILLANCE SR 3.8.8.1 REQUIREMENTS This Surveillance verifies that the inverters are functioning properly with all required circuit breakers closed and uninterruptible AC buses energized from the inverter. The verification of proper voltage and frequency output ensures that the required power is readily available for the instrumentation connected to the uninterruptible AC buses. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to voltage and frequency values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 3).

REFERENCES 1. USAR, Chapter 6.

2. USAR, Chapter 15.

3. Calculation IP-0-0131.

CLINTON B 3.8-77 Revision No. 14-2

Distribution Systems--Operating B 3.8.9 BASES (continued)

SURVEILLANCE SR 3.8.9.1 REQUIREMENTS Meeting this Surveillance verifies that the required AC, DC, and uninterruptible AC bus electrical power distribution systems are functioning properly, with the correct circuit breaker alignment. The correct breaker alignment ensures the appropriate separation and independence of the electrical divisions is maintained, and the appropriate voltage is available to each required bus. The verification of proper voltage availability on the buses ensures that the required voltage is readily available for motive as well as control functions for critical system loads connected to these buses. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to voltage values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 6).

REFERENCES 1. USAR, Chapter 6.

2. USAR, Chapter 15.

3. Regulatory Guide 1.93, December 1974.

4. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.

5. USAR, Section 8.3.

6. Calculation IP-0-0132.

CLINTON B 3.8-87 Revision No. 14-2

Distribution Systems--Shutdown B 3.8.10 BASES ACTIONS A.1, A.2.1, A.2.2, A.2.3,'A.2.4, and A.2.5 (continued)

The Completion Time of immediately is consistent with the required times for actions requiring prompt attention. The restoration of the required distribution subsystems should be completed as quickly as possible in order to minimize the time the plant safety systems may be without power.

SURVEILLANCE SR 3.8.10.1 REQUIREMENTS This Surveillance verifies that the required AC, DC, and uninterruptible AC bus electrical power distribution subsystems are functioning properly, with the buses energized. The v erification of proper voltage availability on the required buses ensures that the required power is readily available for motive as well as control functions for critical system loads connected to these buses. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to voltage values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 3).

REFERENCES 1. USAR, Chapter 6.

2. USAR, Chapter 15.

3. Calculation IP-0-0132.

CLINTON B 3.8-92 Revision No. 14-2

SVC Protection Systems B 3.8.11 BASES ACTIONS B.1 (continued) status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The Completion Time of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is reasonable, taking into account the low probability of an SVC failure occurring in this time period and the realistic potential for an SVC failure to adversely affect plant equipment.

C.1 If the required SVC protection subsystems cannot be restored to OPERABLE status within the required Completion Time, the SVC must be placed in a configuration for which the SVC Protection System LCO does not apply. This is accomplished by disconnecting the associated SVC from the plant auxiliary power system by opening (at least one of) the SVC main circuit breakers. The Completion Time of one hour allows for an orderly disconnection of the SVC, including evaluation of the resultant impact on required voltage for the onsite ESF busses (i.e., for compliance with LCO 3.8.1, "AC Sources-Operating," or LCO 3.8.2, "AC Sources-Shutdown").

SURVEILLANCE SR 3.8.11.1 REQUIREMENTS The SVC local control panel is checked to confirm satisfactory operation of the SVC Protection System(s).

This includes verifying that no warning or trouble lights that could be indicative of SVC Protection System degradation are present, and checking the overall condition and/or status of relays to qualitatively confirm satisfactory operation of the SVC and SVC Protection System.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.8.11.2 A system functional test of each SVC Protection System is performed to ensure that each SVC protection subsystem will actuate to automatically open the associated SVC's main circuit breakers in response to signals associated with SVC failure modes that could potentially damage or degrade plant (continued)

CLINTON B 3.8-96 Revision No. 14-2

SVC Protection Systems B 3.8.11 BASES SURVEILLANCE SR 3.8.11.2 (continued)

REQUIREMENTS equipment. System functional testing should thus include satisfactory operation of the associated relays and testing of the sensors for which failure modes would be undetected. As a minimum, SVC protection subsystem actuation capability should be verified for response to signals, actual or simulated, corresponding to the following potential SVC failure modes or conditions:

(1) Overvoltage (2) Undervoltage (3) Phase Unbalance (4) Harmonics (5) Overcurrent The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. 10CFR50, Appendix A, GDC 17.

2. USAR, Chapter 8.

CLINTON B 3.8-97 Revision No. 14-2

Refueling Equipment Interlocks B 3.9.1 BASES (continued)

SURVEILLANCE SR 3.9.1.1 REQUIREMENTS Performance of a CHANNEL FUNCTIONAL TEST demonstrates each required refueling equipment interlock will function properly when a simulated or actual signal indicative of a required condition is injected into the logic. The test also verifies the relative accuracy of the instrumentation. 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 CHANNEL FUNCTIONAL TEST may be performed by any series of sequential, overlapping, or total channel steps so that the entire channel is tested.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. 10 CFR 50, Appendix A, GDC 26.

2. USAR, Section 7.6.1.1.

3. USAR, Section 15.4.1.1.

CLINTON B 3.9-4 Revision No. 14-2

Refuel Position One-Rod-Out Interlock B 3.9.2 BASES ACTIONS A.1 and A.2 (continued) fuel assemblies. Action must continue until all such control rods are fully inserted. Control rods in core cells containing no fuel assemblies do not affect the reactivity of the core and, therefore, do not have to be inserted.

SURVEILLANCE SR 3.9.2.1 REQUIREMENTS Proper functioning of the refuel position one-rod-out interlock requires the reactor mode switch to be in refuel.

During control rod withdrawal in MODE 5, improper positioning of the reactor mode switch could, in some instances, allow improper bypassing of required interlocks.

Therefore, this Surveillance imposes an additional level of assurance that the refuel position one-rod-out interlock will be OPERABLE when required. By "locking" the reactor mode switch in the proper position (i.e., removing the reactor mode switch key from the console while the reactor mode switch is positioned in refuel), an additional administrative control is in place to preclude operator errors from resulting in unanalyzed operation.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.9.2.2 Performance of a CHANNEL FUNCTIONAL TEST on each channel demonstrates the associated refuel position one-rod-out interlock will function properly when a simulated or actual signal indicative of a required condition is injected into the logic. 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 CHANNEL FUNCTIONAL TEST may be performed by any series of sequential, overlapping, or total channel steps so that the entire channel is tested. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

To perform the required testing, the applicable condition must be entered (i.e., a control rod must be withdrawn from its full-in position). Therefore, this SR has been modified by a Note that states the CHANNEL FUNCTIONAL TEST is not required to be performed until 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after any control rod is withdrawn.

(continued)

CLINTON B 3.9-7 Revision No. 14-2

Refuel Position One-Rod-Out Interlock B 3.9.2 BASES (continued)

REFERENCES 1. 10 CFR 50, Appendix A, GDC 26.

2. USAR, Section 7.6.1.1.

3. USAR, Section 15.4.1.1.

CLINTON B 3. 9-8 Revision No. 14-2

Control Rod Position B 3.9.3 BASES SURVEILLANCE SR 3.9.3.1 (continued)

REQUIREMENTS The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. 10 CFR 50, Appendix A, GDC 26.

2. USAR Section 15.4.1.1.

CLINTON B 3. 9-11 Revision No. 14-2

Control Rod OPERABILITY--Refueling B 3.9.5 BASES SURVEILLANCE SR 3.9.5.1 and SR 3.9.5.2 (continued)

REQUIREMENTS The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.9.5.1 is modified by a Note that allows 7 days after withdrawal of the control rod to perform the Surveillance.

This acknowledges that the control rod must first be withdrawn before performance of the Surveillance and therefore avoids potential conflicts with SR 3.0.3 and SR 3.0.4.

With regard to CRD scram accumulator pressure values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is not considered to be a nominal value with respect to instrument uncertainties.

This requires additional margin to be added to the limit to compensate for instrument uncertainties, for implementation in the associated plant procedures (Ref. 3).

REFERENCES 1. 10 CFR 50, Appendix A, GDC 26.

2. USAR, Section 15.4.1.1.

3. Calculation IP-0-0133.

CLINTON B 3. 9-18 Revision No. 14-2

RPV Water Level--Irradiated Fuel B 3.9.6 BASES SURVEILLANCE SR 3.9.6.1 (continued)

REQUIREMENTS The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to RPV water level values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 5).

REFERENCES 1. Regulatory Guide 1.25, March 1972.

2. USAR, Section 15.7.4.

3. NUREG-0800, Section 15.7.4.

4. 10 CFR 100.11.

5. Calculation IP-0-0134.

CLINTON B 3. 9-21 Revision No. 14-2

RPV Water Level-New Fuel or Control Rods B 3.9.7 BASES ACTIONS A.1 (continued) to ensure that a fuel handling accident cannot occur. The suspension of fuel movement and control rod handling shall not preclude completion of movement of a component to a safe position.

SURVEILLANCE SR 3.9.7.1 REQUIREMENTS Verification of a minimum water level of 23 ft above the top of the irradiated fuel assemblies seated within the RPV ensures that the design basis for the postulated fuel handling accident analysis during refueling operations is met. Water at the required level limits the consequences of damaged fuel rods, which are postulated to result from a fuel handling accident in containment (Ref. 2).

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to RPV water level values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 5).

REFERENCES 1. Regulatory Guide 1.25, March 1972.

2. USAR, Section 15.7.4.

3. NUREG-0800, Section 15.7.4.

4. 10 CFR 100.11.

5. Calculation IP-0-0134.

CLINTON B 3. 9-24 Revision No. 14-2

RHR-High Water Level B 3.9.8 BASES ACTIONS B.1, B.2, B.3, B.4, and B.5 (continued) would not be expected to result in the immediate release of appreciable fission products to the containment atmosphere.

Actions must continue until all requirements of this Condition are satisfied.

C.1 and C.2 If no RHR shutdown cooling subsystem is in operation, an alternate method of coolant circulation is required to be established within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The Completion Time is modified such that 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is applicable separately for each occurrence involving a loss of coolant circulation.

During the period when the reactor coolant is being circulated by an alternate method (other than by the required RHR shutdown cooling subsystem), the reactor coolant temperature must be periodically monitored to ensure proper functioning of the alternate method. The once per hour Completion Time is deemed appropriate.

SURVEILLANCE SR 3.9.8.1 REQUIREMENTS This Surveillance demonstrates that the RHR shutdown cooling subsystem is in operation and circulating reactor coolant.

The required flow rate is determined by the flow rate necessary to provide sufficient decay heat removal capability. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. USAR, Section 5.4.7.

CLINTON B 3.9-28 Revision No. 14-2

RHR-Low Water Level B 3.9.9 BASES ACTIONS B.l, B.2, B.3, and B.4 (continued) required component is inoperable, then it must be restored to OPERABLE status. In this case, the Surveillances may need to be performed to restore the component to OPERABLE status. In addition, at least one door in the upper containment personnel air lock must be closed. The closed air lock door completes the boundary for control of potential radioactive releases. With the appropriate administrative controls however, the closed door can be opened intermittently for entry and exit. This allowance is acceptable due to the need for containment access and due to the slow progression of events which may result from inadequate decay heat removal. Loss of decay heat removal would not be expected to result in the immediate release of appreciable fission products to the containment atmosphere. Actions must continue until all requirements of this Condition are satisfied.

C.1 and C.2 If no RHR shutdown cooling subsystem is in operation, an alternate method of coolant circulation is required to be established within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The Completion Time is modified such that the 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is applicable separately for each occurrence involving a loss of coolant circulation.

During the period when the reactor coolant is being circulated by an alternate method (other than by the required RHR Shutdown Cooling System), the reactor coolant temperature must be periodically monitored to ensure proper function of the alternate method. The once per hour Completion Time is deemed appropriate.

SURVEILLANCE SR 3.9.9.1 REQUIREMENTS This Surveillance demonstrates that one RHR shutdown cooling subsystem is in operation and circulating reactor coolant.

The required flow rate is determined by the flow rate necessary to provide sufficient decay heat removal capability. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. USAR, Section 5.4.7.

CLINTON B 3.9-32 Revision No. 14-2

Reactor Mode Switch Interlock Testing B 3.10.2 BASES (continued)

ACTIONS A.1, A.2, A.3.1, and A.3.2 These Required Actions are provided to restore compliance with the Technical Specifications overridden by this Special Operations LCO. Restoring compliance will also result in exiting the Applicability of this Special Operations LCO.

All CORE ALTERATIONS except control rod insertion, if in progress, are immediately suspended in accordance with Required Action A.1, and all insertable control rods in core cells that contain one or more fuel assemblies are fully inserted within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , in accordance with Required Action A.2. This will preclude potential mechanisms that could lead to criticality. Suspension of CORE ALTERATIONS shall not preclude the completion of movement of a component to a safe condition. Placing the reactor mode switch in the shutdown position will ensure that all inserted control rods remain inserted and result in operation in accordance with Table 1.1-1. Alternatively, if in MODE 5, the reactor mode switch may be placed in the refuel position, which will also result in operating in accordance with Table 1.1-1. A Note is added to Required Action A.3.2 to indicate that this Required Action is not applicable in MODES 3 and 4, since only the shutdown position is allowed in these MODES. The allowed Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months for Required Actions A.2, A.3.1, and A.3.2 provides sufficient time to normally insert the control rods and place the reactor mode switch in the required position, based on operating experience, and is acceptable given that all operations that could increase core reactivity have been suspended.

SURVEILLANCE SR 3.10.2.1 and SR 3.10.2.2 REQUIREMENTS Meeting the requirements of this Special Operations LCO maintains operation consistent with or conservative to operating with the reactor mode switch in the shutdown position (or the refuel position for MODE 5). The functions of the reactor mode switch interlocks that are not in effect, due to the testing in progress, are adequately compensated for by the Special Operations LCO requirements.

The administrative controls are to be periodically verified (by a second licensed operator or other technically qualified member of the unit technical staff) to ensure that the operational requirements continue to be met. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3.10-9 Revision No. 14-2

Reactor Mode Switch Interlock Testing B 3.10.2 BASES (continued)

REFERENCES 1. USAR, Section 7.6.1.1.

2. USAR, Section 15.4.1.1.

CLINTON B 3.1I0-10 Revision No. 14-2

Single Control Rod Withdrawal-Hot Shutdown B 3.10.3 BASES ACTIONS A.1 (continued) of any other LCO's Required Action to insert all control rods. This Required Action includes exiting this Special Operations Applicability LCO by returning the reactor mode switch to the shutdown position. A second Note has been added, which clarifies that this Required Action is only applicable if the requirements not met are for an affected LCO.

A.2.1 and A.2.2 Required Actions A.2.1 and A.2.2 are alternative Required Actions that can be taken instead of Required Action A.1 to restore compliance with the normal MODE 3 requirements, thereby exiting this Special Operations LCO's Applicability.

Actions must be initiated immediately to insert all insertable control rods. Actions must continue until all such control rods are fully inserted. Placing the reactor mode switch in the shutdown position will ensure that all inserted rods remain inserted and restore operation in accordance with Table 1.1-1. The allowed Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months to place the reactor mode switch in the shutdown position provides sufficient time to normally insert the control rods.

SURVEILLANCE SR 3.10.3.1, SR 3.10.3.2, and SR 3.10.3.3 REQUIREMENTS The other LCOs made applicable in this Special Operations LCO are required to have their Surveillances met to establish that this Special Operations LCO is being met. If the local array of control rods is inserted and disarmed while the scram function for the withdrawn rod is not available, periodic verification in accordance with SR 3.10.3.2 is required to preclude the possibility of criticality. SR 3.10.3.2 has been modified by a Note, which clarifies that this SR is not required to be met if SR 3.10.3.1 is satisfied for LCO 3.10.3.d.1 requirements, since SR 3.10.3.2 demonstrates that the alternative LCO 3.10.3.d.2 requirements are satisfied. Also, SR 3.10.3.3 verifies that all control rods other than the control rod being withdrawn are fully inserted. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

CLINTON B 3. 10-14 Revision No. 14-2

Single Control Rod Withdrawal-Hot Shutdown B 3.10.3 BASES (continued)

REFERENCES 1. USAR, Section 15.4.1.1.

CLINTON B 3. 10-15 Revision No. 14-2

Single Control Rod Withdrawal-Cold Shutdown B 3.10.4 BASES (continued)

SURVEILLANCE SR 3.10.4.1, SR 3.10.4.2, SR 3.10.4.3, and SR 3.10.4.4 REQUIREMENTS The other LCOs made applicable by this Special Operations LCO are required to have their associated Surveillances met to establish that this Special Operations LCO is being met.

If the local array of control rods is inserted and disarmed whil: the scram function for the withdrawn rod is not available, periodic verification is required to ensure that the possibility of criticality remains precluded. The control rods can be hydraulically disarmed by closing the drive water and exhaust water isolation valves.

Electrically, the control rods can be disarmed by disconnecting power from all four directional control valve solenoids. Verification that all the other control rods are fully inserted is required to meet the SDM requirements.

Verification that a control rod withdrawal block has been inserted ensures that no other control rods can be inadvertently withdrawn under conditions when position indication instrumentation is inoperable for the affected control rod. The Surveillance Frequency is controlled under'the Surveillance Frequency Control Program.

SR 3.10.4.2 and SR 3.10.4.4 have been modified by Notes, which clarify that these SRs are not required to be met if the alternative requirements demonstrated by SR 3.10.4.1 are satisfied.

REFERENCES 1. USAR, Section 15.4.1.1.

CLINTON B 3.10-20 Revision No. 14-2

Single CRD Removal--Refueling B 3.10.5 BASES SURVEILLANCE SR 3.10.5.1, SR 3.10.5.2, SR 3.10.5.3, SR 3.10.5.4, and REQUIREMENTS SR 3.10.5.5 (continued)

Periodic verification of the administrative controls established by this Special Operations LCO is prudent to preclude the possibility of an inadvertent criticality. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. USAR, Section 15.4.1.1.

CLINTON B 3.10-25 Revision No. 14-2

Multiple Control Rod Withdrawal--Refueling B 3.10.6 BASES (continued)

APPLICABILITY Operation in MODE 5 is controlled by existing LCOs. The exceptions from other LCO requirements (e.g., the ACTIONS of LCO 3.9.3, LCO 3.9.4 or LCO 3.9.5) allowed by this Special Operations LCO are appropriately controlled by requiring all fuel to be removed from cells whose "full in" indicators are allowed to be bypassed.

ACTIONS A.1, A.2, A.3.1, and A.3.2 If one or more of the requirements of this Special Operations LCO are not met, the immediate implementation of these Required Actions commences activities which will restore operation consistent with the normal requirements for refueling (i.e., all control rods inserted in core cells containing one or more fuel assemblies) or with the exceptions granted by this Special Operations LCO. The Completion Times are intended to require that these Required Actions be implemented in a very short time and carried through in an expeditious manner.

SURVEILLANCE SR 3.10.6.1, SR 3.10.6.2, and SR 3.10.6.3 REQUIREMENTS Periodic verification of the administrative controls established by this Special Operations LCO is prudent to preclude the possibility of an inadvertent criticality. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. USAR, Section 15.4.1.1.

CLINTON B 3.10-28 Revision No. 14-2

SDM Test-Refueling B 3.10.8 BASES (continued)

SURVEILLANCE SR 3.10.8.1 SR 3.10.8.2 and SR 3.10.8.3 REQUIREMENTS The other LCOs made applicable in this Special Operations LCO are required to have applicable Surveillances met to establish that this Special Operations LCO is being met.

However, the control rod withdrawal sequences during the SDM tests may be enforced by the RPC (LCO 3.3.2.1, Function lb, MODE 2 requirements) or by a second licensed operator or other qualified member of the technical staff. As noted, either the applicable SRs for the RPC (LCO 3.3.2.1) must be satisfied according to the applicable Frequencies (SR 3.10.8.2) or the proper movement of control rods must be verified (SR 3.10.8.3). This latter verification (i.e.,

SR 3.10.8.3) must be performed during control rod movement to prevent deviations from the specified sequence. These surveillances provide adequate assurance that the specified test sequence is being followed.

SR 3.10.8.4 Periodic verification of the administrative controls established by this LCO will ensure that the reactor is operated within the bounds of the safety analysis. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.10.8.5 Coupling verification is performed to ensure the control rod is connected to the control rod drive mechanism and will perform its intended function when necessary. The verification is required to be performed any time a control rod is withdrawn to the "full out" notch position or prior to declaring the control rod OPERABLE after work on the control rod or CRD System that could affect coupling. This Frequency is acceptable, considering the low probability that a control rod will become uncoupled when it is not being moved as well as operating experience related to uncoupling events.

(continued)

CLINTON B 3.10-37 Revision No. 14-2

SDM Test-Refueling B 3.10.8 BASES SURVEILLANCE SR 3.10.8.6 REQUIREMENTS (continued) CRD charging water header pressure verification is performed to ensure the motive force is available to scram the control rods in the event of a scram signal. A minimum accumulator pressure is specified, below which the capability of the accumulator to perform its intended function becomes degraded and the accumulator is considered inoperable. The minimum accumulator pressure of 1520 psig is well below the expected pressure of 1750 psig. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to CRD charging water header pressure values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is not considered to be a nominal value with respect to instrument uncertainties. This requires additional margin to be added to the limit to compensate for instrument uncertainties, for implementation in the associated plant procedures (Ref.

3).

REFERENCES 1. NEDE-24011-P-A, "General Electric Standard Application for Reactor Fuel, GESTAR II" (latest approved revision).

2. USAR, Section 15.4.9.

3. Calculation IP-0-0136.

CLINTON B 3.10-38 Revision No. 14-2

Training Startups B 3.10.9 BASES (continued)

SURVEILLANCE SR 3.10.9.1 and SR 3.10.9.2 REQUIREMENTS Periodic verification that the THERMAL POWER and reactor coolant temperature limits of this Special Operations LCO are satisfied will ensure that the stored energy in the reactor core and reactor coolant'are sufficiently low to preclude the need for all RHR subsystems to be aligned in the LPCI mode of operation. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to THERMAL POWER and reactor coolant temperature values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Refs. 2, 3).

REFERENCES 1. USAR, Section 6.3.3.

2. Calculation IP-0-0137.

3. Calculation IP-0-0138.

CLINTON B 3. 10-41 Revision No. 14-2

Single Control Rod Withdrawal - Refueling B 3.10.10 BASES (continued)

ACTIONS A Note has been provided to modify the ACTIONS related to a single control rod withdrawal while in MODE 5. 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 that 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 each requirement of the LCO not met provide appropriate compensatory measures for separate requirements that are not met. As such, a Note has been provided that allows separate Condition entry for each requirement of the LCO.

A.1 and A.2 If one or more of the requirements specified in this Special Operations LCO are not met, all CORE ALTERATIONS except control rod insertion, if in progress, must be immediately suspended in accordance with Required Action A.1, and actions must be initiated immediately to fully insert all control rods in accordance with Required Action A.2. This will preclude potential mechanisms that could lead to criticality. Suspension of CORE ALTERATIONS shall not preclude the completion of movement of a component to a safe condition and actions to fully insert all insertable control rods must continue until all control rods are fully inserted.

SURVEILLANCE SR 3.10.10.1 and SR 3.10.10.2 REQUIREMENTS Verification that all the control rods, other than the control rod withdrawn for testing, are fully inserted is required to ensure the SDM is within limits. Verification that no other CORE ALTERATIONS are being made is required to ensure the assumptions of the safety analyses are satisfied.

Periodic verification of the administrative controls established by this Special Operations LCO is prudent to preclude the possibility of an inadvertent criticality.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. USAR, Section 15.4.1.1.

CLINTON B 3.10-45 Revision No. 14-2

Attachment 2 to U-604075 Revision 14 Bases Rev 14-3 Pages

TABLE OF CONTENTS (continued) 3.7 PLANT SYSTEM S ...................................................................................................... 3.7-1 3.7.1 Division I and 2 Shutdown Service Water (SX) Subsystems and Ultimate Heat Sink (UHS) ................................................................... 3.7-1 3.7.2 Division 3 Shutdown Service Water (SX)

Subsystem ................................................................................................... 3.7-3 3.7.3 Control Room Ventilation System ...................................................................... 3.7-4 3.7.4 Control Room Air Conditioning (AC) System .................................................... 3.7-8 3.7.5 M ain Condenser Offgas ....................................................................................... 3.7-l1 3.7.6 M ain Turbine Bypass System .............................................................................. 3.7-13 3.7.7 Fuel Pool W ater Level ......................................................................................... 3.7-15 B 3.7 PLANT SYSTEM S ...................................................................................................... B 3.7-1 B 3.7.1 Division 1 and 2 Shutdown Service Water (SX)

Subsystems and Ultimate Heat Sink (UHS) ............................................... B 3.7-1 B 3.7.2 Division 3 Shutdown Service W ater Subsystem (SX) ........................................ B 3.7-8 B 3.7.3 Control Room Ventilation System ...................................................................... B 3.7-11 B 3.7.4 Control Room Air Conditioning (AC) System .................................................... B 3.7-22 B 3.7.5 M ain Condenser Offgas ....................................................................................... B 3.7-28 B 3.7.6 M ain Turbine Bypass System .............................................................................. B 3.7-32 B 3.7.7 Fuel Pool Water Level ......................................................................................... B 3.7-36 3.8 ELECTRICAL POWER SYSTEM S ............................................................................ 3.8-1 3.8.1 AC Sources -Operating ....................................................................................... 3.8-1 3.8.2 AC Sources - Shutdown ....................................................................................... 3.8-16 3.8.3 Diesel Fuel Oil, Lube Oil, and Starting Air ........................................................ 3.8-20 3.8.4 DC Sources - Operating ....................................................................................... 3.8-24 3.8.5 DC Sources - Shutdown ...................................................................................... 3.8-27 3.8.6 Battery Cell Parameters ....................................................................................... 3.8-30 3.8.7 Inverters - Operating ............................................................................................ 3.8-34 3.8.8 Inverters - Shutdown ............................................................................................ 3.8-36 3.8.9 Distribution System s - Operating ......................................................................... 3.8-39 3.8.10 Distribution System s - Shutdown ......................................................................... 3.8-42 3.8.11 Static VAR Compensator (SVC) Protection System s ......................................... 3.8-44 B 3.8 ELECTRICAL POWER SYSTEM S ............................................................................ B 3.8-1 B 3.8.1 AC Sources- Operating ....................................................................................... B 3.8-1 B 3.8.2 AC Sources- Shutdown ....................................................................................... B 3.8-33 B 3.8.3 Diesel Fuel Oil, Lube Oil, and Starting Air ....................................................... B 3.8-40 B 3.8.4 DC Sources- Operating ....................................................................................... B 3.8-4 9 B 3.8.5 DC Sources - Shutdown ....................................................................................... B 3.8-59 B 3.8.6 Battery Cell Parameters ....................................................................................... B 3.8-64 B 3.8.7 Inverters - Operating ............................................................................................ B 3.8-69 B 3.8.8 Inverters - Shutdown ........................................................................................... B 3.8-74 B 3.8.9 Distribution System s- Operating ......................................................................... B 3.8-78 B 3.8.10 Distribution System s-Shutdown ......................................................................... B 3.8-89 B 3.8-11 Static VAR Compensator (SVC) Protection Systems ......................................... B 3.8-93 (continued)

CLINTON Revision No. 14-3 vi

Main Turbine Bypass System B 3.7.6 B 3.7 PLANT SYSTEMS B 3.7.6 Main Turbine Bypass System BASES BACKGROUND The Main Turbine Bypass System is designed to control steam pressure when reactor steam generation exceeds turbine requirements during unit startup, sudden load reduction, and cooldown. It allows excess steam flow from the reactor to the condenser without going through the turbine. The bypass capacity of the system is 28.8% of the Nuclear Steam Supply System rated steam flow. Sudden load reductions within the capacity of the steam bypass can be accommodated without reactor scram. The Main Turbine Bypass System consists of two valve chests (each with three bypass valves) connected to the main steam lines between the main steam isolation valves and the turbine stop valves. Each of the bypass valves is sequentially operated by hydraulic cylinders. The bypass valves are controlled by the pressure regulation function of the Turbine Electro Hydraulic Control System, as discussed in the USAR, Section 7.7.1.5 (Ref. 1). The bypass valves are normally closed, and the pressure regulator controls the turbine control valves, directing all steam flow to the turbine. If the speed governor or the load limiter restricts steam flow to the turbine, the pressure regulator controls the system pressure by opening the bypass valves. When the bypass valves open, the steam flows from the bypass chests, through connecting piping, to the main condenser.

APPLICABLE The Main Turbine Bypass System is assumed to function during SAFETY ANALYSES the design basis feedwater controller failure, maximum demand event, described in the USAR, Section 15.1.2 (Ref. 2). Opening the bypass valves during the pressurization event mitigates the increase in reactor vessel pressure, which affects the MCPR and LHGR during the event. An inoperable Main Turbine Bypass System may result in reactor power limitations and MCPR and LHGR penalties.

An inoperable MTBS is defined as one or more bypass valves being inoperable.

The Main Turbine Bypass System satisfies Criterion 3 of the NRC Policy Statement.

LCO The Main Turbine Bypass System is required to be OPERABLE to limit peak pressure in the main steam lines and maintain reactor pressure within acceptable limits during events that cause rapid pressurization, such that the Safety Limit MCPR (continued)

CLINTON B 3.7-32 Revision No. 14-3

Main Turbine Bypass System B 3.7.6 BASES LCO is not exceeded. With an inoperable Main Turbine Bypass (continued) System, reactor power may be limited in accordance with the cycle-dependent COLR and modification to MCPR limits (LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)") AND LHGR limits (LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)") may be applied in accordance with the cycle-dependent COLR to allow continued operation. An OPERABLE Main Turbine Bypass System requires the bypass valves to open in response to increasing main steam line pressure. This response is within the assumptions of the applicable analysis (Ref. 2).

The reactor power limitations and the MCPR and LHGR limits for an inoperable Main Turbine Bypass System are specified in the COLR.

APPLICABILITY The Main Turbine Bypass System is required to be OPERABLE at

-> 21.6% RTP to ensure that the fuel cladding integrity Safety Limit and the cladding 1% plastic strain limit are not violated during the feedwater controller failure, maximum demand event. As discussed in the Bases for LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)," and LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)," sufficient margin to these limits exists

< 21.6% RTP. Therefore, these requirements are only necessary when operating at or above this power level.

ACTIONS A.1 If the Main Turbine Bypass System is inoperable (one or more bypass valves inoperable), and the reactor power limit for an inoperable Main Turbine Bypass System, and the MCPR and LHGR limits for an inoperable Main Turbine Bypass System, as specified in the COLR, are not applied, the assumptions of the design basis transient analysis may not be met. Under such circumstances, prompt action should be taken to restore the Main Turbine Bypass System to OPERABLE status or limit reactor power and apply the MCPR and LHGR limits as specified in the COLR. The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is reasonable, based on the time to complete the Required Action and the low probability of an event occurring during this period requiring the Main Turbine Bypass System.

B.1 If the Main Turbine Bypass System cannot be restored to OPERABLE status within the associated Completion Time, or the reactor power limit for an inoperable Main Turbine Bypass System, as specified in the COLR is not applied, and the MCPR and LHGH limits for an inoperable Main Turbine (continued)

CLINTON B 3.7-33 Revision No. 14-3

Main Turbine Bypass System B 3.7.6 BASES ACTIONS B.l (continued)

Bypass System, as specified in the COLR, are not applied within the associated Completion Time, THERMAL POWER must be reduced to < 21.6% RTP. As discussed in the Applicability section, section, operation at < 21.6% RTP results in sufficient margin to the required limits, and the Main Turbine Bypass System is not required to protect fuel integrity during the feedwater controller failure, maximum demand event. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

SURVEILLANCE SR 3.7.6.1 REQUIREMENTS Cycling each main turbine bypass valve through one complete cycle of full travel demonstrates that the valves are mechanically OPERABLE and will function when required. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.7.6.2 The Main Turbine Bypass System is required to actuate automatically to perform its design function. This SR demonstrates that, with the required system initiation signals, the valves will actuate to their required position.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.7.6.3 This SR ensures that the TURBINE BYPASS SYSTEM RESPONSE TIME is in compliance with the assumptions of the appropriate safety analysis. The response time limits (bypass valve begins to open in

0.1 seconds and 80% of turbine bypass system capacity is established in

0.3 seconds) are specified in applicable surveillance test procedures. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to TURBINE BYPASS SYSTEM RESPONSE TIME values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 3).

(continued)

CLINTON B 3.7-34 Revision No. 14-3

Main Turbine Bypass System B 3.7.6 BASES (continued)

REFERENCES 1. USAR, Section 7.7.1.5.

2. USAR, Section 15.1.2.

3. Calculation IP-0-0104.

CLINTON B 3. 7-35 Revision No. 14-3

Fuel Pool Water Level B 3.7.7 B 3.7 PLANT SYSTEMS B 3.7.7 Fuel Pool Water Level BASES BACKGROUND The minimum water level in the spent fuel storage pool and upper containment fuel storage pool meets the assumptions of iodine decontamination factors following a fuel handling accident.

A general description of the spent fuel storage pool and upper containment fuel storage pool design is found in the USAR, Section 9.1.2 (Ref. 1). The assumptions of the fuel handling accident are found in the USAR, Section 15.7.4 (Ref. 2).

APPLICABLE The water level above the irradiated fuel assemblies is an SAFETY ANALYSES explicit assumption of the fuel handling accident. A fuel handling accident is evaluated to ensure that the radiological consequences (calculated whole body and thyroid doses at the exclusion area and low population zone boundaries) are

25% (NUREG-0800, Section 15.7.4, Ref. 3) of the 10 CFR 100 (Ref. 4) exposure guidelines. A fuel handling accident could release a fraction of the fission product inventory by breaching the fuel rod cladding as discussed in the Regulatory Guide 1.25 (Ref. 5).

The fuel handling accident is evaluated for the dropping of an irradiated fuel assembly onto stored fuel bundles. The consequences of a fuel handling accident inside the fuel building and inside containment are documented in Reference 2. The water levels in the spent fuel storage, pool and upper containment fuel storage pool provide for absorption of water soluble fission product gases and transport delays of soluble and insoluble gases that must pass through the water before being released to the primary or secondary containment atmosphere, as applicable. This absorption and transport delay reduces the potential radioactivity of the release during a fuel handling accident.

The fuel pool water level satisfies Criterion 2 of the NRC Policy Statement.

(continued)

CLINTON B 3.7-36 Revision No. 14-3

Fuel Pool Water Level B 3.7.7 BASES (continued)

LCO The specified water level preserves the assumption of the fuel handling accident analysis (Ref. 2). As such, it is the minimum required for fuel movement within the spent fuel storage pool and upper containment fuel storage pool.

APPLICABILITY This LCO applies whenever movement of irradiated fuel assemblies occurs in the associated fuel storage racks since the potential for a release of fission products exists.

ACTIONS A.1 Required Action A.l is modified by a Note indicating that LCO 3.0.3 does not apply. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, inability to suspend movement of irradiated fuel assemblies is not a sufficient reason to require a reactor shutdown.

When the initial conditions for an accident cannot be met, steps should be taken to preclude the accident from occurring. With either fuel pool level less than required, the movement of irradiated fuel assemblies in the associated storage pool is suspended immediately. Suspension of this activity shall not preclude completion of movement of an irradiated fuel assembly to a safe position. This effectively precludes a spent fuel handling accident from occurring in the associated fuel storage pool.

SURVEILLANCE SR 3.7.7.1 REQUIREMENTS This SR verifies that sufficient water is available in the event of a fuel handling accident. The water level in the spent fuel storage pool and upper containment fuel storage pool must be checked periodically. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to fuel pool water level values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 6).

(continued)

CLINTON B 3 .7-37 Revision No. 14-3

Fuel Pool Water Level B 3.7.7 BASES (continued)

REFERENCES 1 . USAR, Section 9.1.2.

2. USAR, Section 15.7.4.

3. NUREG-0800, Section 15.7.4, Revision 1, July 1981.

4. 10 CFR 100.

5. Regulatory Guide 1.25, March 1972.

6. Calculation IP-0-0105.

CLINTON B 3.7-38 Revision No. 14-3

Attachment 2 to U-604075 Revision 14 Bases Rev 14-4 Pages

AC Sources--Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.8 REQUIREMENTS (continued) Transfer of each 4.16 kV ESF bus power supply from the normal offsite circuit to the alternate offsite circuit demonstrates the OPERABILITY of the alternate circuit. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by a Note. The reason for the Note is that, during operation with the reactor critical, performance of this SR could cause perturbations to the electrical distribution systems that could challenge continued steady state operation and, as a result, plant safety systems (The Note is not applicable to Division 3 AC Sources). Credit may be taken for unplanned events that satisfy this SR. Examples of unplanned events may include:

1) Unexpected operational events which cause the equipment to perform the function specified by this surveillance, for which adequate documentation of the required performance is available; and

2) Post maintenance testing that requires performance of this Surveillance in order to restore the component to OPERABLE, provided the maintenance was required, or performed in conjunction with maintenance required to maintain OPERABILITY or reliability.

SR 3.8.1.9 Each DG is provided with an engine overspeed trip to prevent damage to the engine. Recovery from the transient caused by the loss of a large load could cause diesel engine overspeed, which, if excessive, might result in a trip of the engine. This Surveillance demonstrates the DG load response characteristics and capability to reject a load equivalent to at least as large as the largest single load while maintaining a specified margin to the overspeed trip.

(continued)

CLINTON B 3.8-18 Revision No. 14-4

AC Sources -Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.11 (continued)

REQUIREMENTS full flow, or RHR systems performing a decay heat removal function are not desired to be realigned to the ECCS mode of operation. In lieu of actual demonstration of the connection and loading of these loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by two Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions. Standby conditions mean that the lube oil is heatedby the jacket water and continuously circulated through a portion of the system as recommended by the vendor. Engine jacket water is heated by an immersion heater and circulates through the system by natural circulation. This allowance is not intended to impose a maximum limit on engine temperatures. The reason for Note 2 is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge plant safety systems (Note 2 is not applicable to the Division 3 DG). Credit may be taken for unplanned events that satisfy this SR.

Examples of unplanned events may include:

1) Unexpected operational events which cause the equipment to perform the function specified by-this Surveillance, for which adequate documentation of the required performance is available; and

2) Post maintenance testing that requires performance of this Surveillance in order to restore the component to OPERABLE, provided the maintenance was required, or performed in conjunction with maintenance required to maintain OPERABILITY or reliability.

(continued)

CLINTON B 3.8-21 Revision No. 14-4

AC Sources--Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.12 REQUIREMENTS (continued) This Surveillance demonstrates that the DG automatically starts and achieves the required voltage and frequency within the specified time (12 seconds) from the design basis actuation signal (LOCA signal) and operates for Ž 5 minutes.

The 5 minute period provides sufficient time to demonstrate stability.

With regard to DG start time, required voltage and frequency values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is not considered to be a nominal value with respect to instrument uncertainties. This requires additional margin to be added to the limit to compensate for instrument uncertainties, for implementation in the associated plant procedures (Refs. 17, 18, 19, 22, 23).

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by two Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions. Standby conditions mean that the lube oil is heated by the jacket water and continuously circulated through a portion of the system as recommended by the vendor. Engine jacket water is heated by an immersion heater and circulates through the system by natural circulation. This allowance is not intended to impose a maximum limit on engine temperatures. The reason for Note 2 is that during operation with the reactor critical, performance of this SR could cause perturbations to the electrical distribution systems that could challenge continued steady state operation and, as a result, plant safety systems (Note 2 is not applicable to the Division 3 DG). Credit may be taken for unplanned events that satisfy this SR. Examples of unplanned events may include:

(continued)

CLINTON B 3.8-22 Revision No. 14-4

AC Sources--Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.16 (continued)

REQUIREMENTS This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems (This Note is not applicable to the Division 3 DG). Credit may be taken for unplanned events that satisfy this SR. Examples of unplanned events may include:

1) Unexpected operational events which cause the equipment to perform the function specified by this Surveillance, for which adequate documentation of the required performance is available; and

2) Post maintenance testing that requires performance of this Surveillance in order to restore the component to OPERABLE, provided the maintenance was required, or performed in conjunction with maintenance required to maintain OPERABILITY or reliability.

SR 3.8.1.17 Demonstration of the test mode override is consistent with the recommendations of Regulatory Guide 1.108 (Ref. 10),

paragraph 2.a. (8)and ensures that the DG availability under accident conditions is not compromised as the result of testing. Except as clarified below for the Division 3 DG, interlocks to the LOCA sensing circuits cause the DG to automatically reset to ready-to-load operation if an ECCS initiation signal is received during operation in the test mode. Ready-to-load operation is defined as the DG running at rated speed and voltage with the DG output breaker open.

These provisions for automatic switchover are required by IEEE-308 (Ref. 14), paragraph 6.2.6(2), as further amplified by IEEE 387, sections 5.6.1 and 5.6.2. (Clarification regarding conformance of the Division 3 DG design to these standards is provided in the USAR, Chapter 8 (Reference 2).)

Automatic switchover from the test mode to ready-to-load operation for the division 3 DG is also demonstrated, as described above, by ensuring that DG control logic automatically resets in response to a LOCA signal during the test mode and confirming that ready-to-load operation is attained (as evidenced by the DG running with the output breaker open). However, with the DG governor initially operating in a "droop" condition during the test mode, operator action may be tequired to reset the governor for (continued)

CLINTON B 3. 8-27 Revision No. 14-4

AC Sources--Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.19 REQUIREMENTS (continued) In the event of a DBA coincident with a loss of offsite power, the DGs are required to supply the necessary power to ESF systems so that the fuel, .RCS, and containment design limits are not exceeded.

This Surveillance demonstrates the DG operation, as discussed in the Bases for SR 3.8.1.11, during a loss of offsite power actuation test signal in conjunction with an ECCS initiation signal. For load shedding effected via shunt trips that are actuated in response to a LOCA signal (i.e., "ECCS initiation signal"), this surveillance includes verification of the shunt trips (for Divisions 1 and 2 only) in response to LOCA signals originating in the ECCS initiation logic as well as the Containment and Reactor Vessel Isolation and Control System actuation logic. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by two Notes. The reason for Note I is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions. Standby conditions mean that the lube oil is heated by the jacket water and continuously circulated through a portion of the system as recommended by the vendor. Engine jacket water is heated by an immersion heater and circulates through the system by natural circulation. This allowance is not intended to impose a maximum limit on engine temperatures. The reason for Note 2 is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge plant safety systems (Note 2 is not applicable to the Division 3 DG).

Credit may be taken for unplanned events that satisfy this SR. Examples of unplanned events may include:

(continued)

CLINTON B 3.8-30 Revision No. 14-4

Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 BASES (continued)

APPLICABILITY The AC sources, LCO 3.8.1 and LCO 3.8.2, are required to ensure the availability of the required power to shut down the reactor and maintain it in a safe shutdown condition after an AOO or a postulated DBA. Since stored diesel fuel oil, lube oil, and starting air subsystem support LCO 3.8.1 and LCO 3.8.2, stored diesel fuel oil, lube oil, and starting air are required to be within limits when the associated DG is required to be OPERABLE.

ACTIONS The Actions Table is modified by a Note indicating that separate Condition entry is allowed for each DG. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable DG subsystem. Complying with the Required Actions for one inoperable DG subsystem may allow for continued operation, and subsequent inoperable DG subsystem(s) are governed by separate Condition entry and application of associated Required Actions.

A.1 In this Condition, the 7 day fuel oil supply for a DG is not available. However, the Condition is restricted to fuel oil level reductions that maintain at least a 6 day supply. The fuel oil level equivalent to a 6 day supply for the Division 1 DG is 43,810 gallons, for the Division 2 DG is 38,572 gallons, and for the Division 3 DG is 25,286 gallons.

These circumstances may be caused by events such as:

a. Full load operation required after an inadvertent start while at minimum required level; or

b. Feed and bleed operations that may be necessitated by increasing particulate levels or any number of other oil quality degradations.

This restriction allows sufficient time for obtaining the requisite replacement volume and performing the analyses required prior to addition of the fuel oil to the tank. A period of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months is considered sufficient to complete restoration of the required level prior to declaring the DG inoperable. This period is acceptable based on the remaining capacity (> 6 days), the fact that procedures will be initiated to obtain replenishment, and the low probability of an event during this brief period.

(continued)

CLINTON B 3.8B-42 Revision No. 14-4

Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 BASES ACTIONS B.1 (continued)

In this condition, the 7 day lube oil inventory, i.e., sufficient lube oil to support 7 days of continuous DG operation at full load conditions, is not available.

However, the Condition is restricted to lube oil volume reductions that maintain at least a 6 day supply. The lube oil equivalent to a 6 day supply for each 16 cylinder diesel engine is 327 gallons and for each 12 cylinder diesel engine is 269 gallons. This restriction allows sufficient time for obtaining the requisite replacement volume. A period of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months is considered sufficient to complete restoration of the required volume prior to declaring the DG inoperable.

This period is acceptable based on the remaining capacity

(> 6 days), the low rate of usage, the fact that procedures will be initiated to obtain replenishment, and the low probability of an event during this brief period.

C.1 This Condition is entered as a result of a failure to meet the acceptance criterion for particulates. Normally, trending of particulate levels allows sufficient time to correct high particulate levels prior to reaching the limit of acceptability. Poor sample procedures (bottom sampling),

contaminated sampling equipment, and errors in laboratory analysis can produce failures that do not follow a trend.

Since the presence of particulate does not mean failure of the fuel oil to burn properly in the diesel engine, since particulate concentration is unlikely to change significantly between Surveillance Frequency intervals, and since proper engine performance has been recently demonstrated (within 31 days), it is prudent to allow a brief period prior to declaring the associated DG inoperable. The 7 day Completion Time allows for further evaluation, resampling, and re-analysis of the DG fuel oil.

D.1 With the new fuel oil properties defined in the Bases for SR 3.8.3.3 not within the required limits, a period of 30 days is allowed for restoring the stored fuel oil properties. This period provides sufficient time to test the stored fuel oil to determine that the new fuel oil, when mixed with previously stored fuel oil, remains acceptable, to restore the stored fuel oil properties. This restoration (continued)

CLINTON B 3.8-43 Revision No. 14-4

Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 BASES ACTIONS D.l (continued) may involve feed and bleed procedures, filtering, or a combination of these procedures. Even if a DG start and load was required during this time interval and the fuel oil properties were outside limits, there is high likelihood that the DG would still be capable of performing its intended function.

E.1 With the required starting air receiver pressure < 200 psig, sufficient capacity for multiple DG start attempts may not exist. However, as long as the receiver pressure is

> 140 psig, there is adequate capacity for at least one start attempt, and the DG can be considered OPERABLE while the air receiver pressure is restored to the required limit.

A period of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months is considered sufficient to complete restoration to the required pressure prior to declaring the DG inoperable. This period is acceptable based on the remaining air start capacity, the fact that most DG starts are accomplished on the first attempt, and the low probability of an event during this brief period.

F.1 With a Required Action and associated Completion Time not met, or the stored diesel fuel oil, lube oil, or starting air subsystem not within limits for reasons other than addressed by Conditions A through E, the associated DG may be incapable of performing its intended function and must be immediately declared inoperable.

SURVEILLANCE SR 3.8.3.1 REQUIREMENTS This SR provides verification that there is an adequate inventory of fuel oil in the storage tanks to support each DG's operation for 7 days at maximum expected post LOCA loading. The fuel oil level equivalent to a 7 day supply at the maximum post-LOCA load demand for the Division 1 DG is 51,000 gallons, for the Division 2 DG is 45,000 gallons, and for the Division 3 DG is 29,500 gallons. The required fuel storage volume is determined using the known correlation of diesel fuel oil absolute specific gravity or API gravity to energy content, the required diesel generator output, and the corresponding fuel consumption rate. SR 3.8.3.3 requires new fuel to be tested to verify that the absolute specific gravity or API gravity is within the range assumed in the diesel fuel oil consumption calculations. The 7 day period is sufficient time to place the unit in a safe shutdown condition and to bring in replenishment fuel from an offsite location.

(continued)

CLINTON B 3.8-44 Revision No. 14-4

Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 BASES SURVEILLANCE SR 3.8.3.1 (continued)

REQUIREMENTS The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to fuel oil inventory values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 11).

SR 3.8.3.2 This Surveillance ensures that sufficient lube oil inventory is available to support at least 7 days of maximum expected post LOCA load operation for each DG. The lube oil level equivalent to a 7 day supply for each 16 cylinder diesel engine is 347 gallons and for each 12 cylinder diesel engine is 284 gallons and is based on the DG manufacturer's consumption values for the run time of the DG. Implicit in this SR is the requirement to verify the capability to transfer the lube oil from its storage location to the DG when the DG lube oil sump does not hold adequate inventory for 7 days of maximum expected post LOCA load operation without the level reaching the manufacturer's recommended minimum level.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

With regard to lube oil inventory values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 8).

SR 3.8.3.3 The tests of fuel oil prior to addition to the storage tanks are a means of determining whether new fuel oil is of the appropriate grade and has not been contaminated with substances that would have an immediate detrimental impact on diesel engine combustion and operation. If results from these tests are within acceptable limits, the fuel oil may be added to the storage tanks without concern for contaminating the entire volume of fuel oil in the storage tanks. These tests are to be conducted prior to adding the new fuel to the storage tank(s), but in no case is the time between the sample (and corresponding results) of new fuel and addition of new fuel oil to the storage tanks to exceed 31 days. The limits and applicable ASTM Standards for the (continued)

CLINTON B 3.8-45 Revision No. 14-4

Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 BASES SURVEILLANCE SR 3.8.3.4 (continued)

REQUIREMENTS With regard to air start capacity values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 10).

SR 3.8.3.5 Microbiological fouling is a major cause of fuel oil degradation. There are numerous bacteria that can grow in fuel oil and cause fouling, but all must have a water environment in order to survive. Periodic removal of water from the storage tanks eliminates the necessary environment for bacterial survival. This is the most effective means of controlling microbiological fouling. In addition, it eliminates the potential for water entrainment in the fuel oil during DG operation. Water may come from any of several sources, including condensation, contaminated fuel oil, and from breakdown of the fuel oil by bacteria.

Frequent checking for and removal of accumulated water minimizes fouling and provides data regarding the watertight integrity of the fuel oil system. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. This SR is for preventive maintenance.

The presence of water does not necessarily represent a failure of this SR provided that accumulated water is removed during performance of the Surveillance.

REFERENCES 1. USAR, Section 9.5.4.

2. Regulatory Guide 1.137.

3. ANSI N195, 1976.

4. USAR, Chapter 6.

5. USAR, Chapter 15.

6. ASTM Standards: D4057-95; D1298-99; D975-06b; D4176-93; D6217-98.

7. Deleted.

8. Calculation IP-0-0120.

9. Calculation IP-0-0121.

10. Calculation IP-0-0122.

11. Calculation IP-C-0006.

CLINTON B 3.8-48 Revision No. 14-4

Attachment 2 to U-604075 Revision 14 Bases Rev 14-5 Pages

Reactivity Anomalies B 3.1.2 BASES BACKGROUND is critical at RTP, the excess positive reactivity is (continued) compensated by burnable absorbers (if any), control rods, and whatever neutron poisons (mainly xenon and samarium) are present in the fuel.

The predicted core reactivity, as represented by core keffective (keff), is calculated by a 3D core simulator code as a function of cycle exposure. This calculation is performed for projected operating states and conditions throughout the cycle. The measured or monitored core ke.f is calculated by the core monitoring system for actual plant conditions and is then compared to the predicted value for the cycle exposure.

APPLICABLE Accurate prediction of core reactivity is either an explicit SAFETY ANALYSES or implicit assumption in the accident analysis evaluation (Ref. 2). In particular, SDM and reactivity transients, such as control rod withdrawal accidents or rod drop accidents, are very sensitive to accurate prediction of core reactivity. These accident analysis evaluations rely on computer codes that have been qualified against available test data, operating plant data, and analytical benchmarks.

Monitoring reactivity anomaly provides additional assurance that the nuclear methods provide an accurate representation of the core reactivity.

The comparison between measured and predicted initial core reactivity provides a normalization for the calculational models used to predict core reactivity. If the measured and predicted core keff for identical core conditions at BOC do not reasonably agree, then the assumptions used in the reload cycle design analysis or the calculation models used to predict core keff may not be accurate. If reasonable agreement between measured and predicted core reactivity exists at BOC, then the prediction may be normalized to the measured value. Thereafter, any significant deviations in the measured core keff from the predicted core keff that I develop during fuel depletion may be an indication that the assumptions of the DBA and transient analyses are no longer valid, or that an unexpected change in core conditions has occurred.

Reactivity anomalies satisfy Criterion 2 of the NRC Policy Statement.

(continued)

CLINTON B 3.1-9 Revision No. 14-5

Reactivity Anomalies B 3.1.2 BASES (continued)

LCO The reactivity anomaly limit is established to ensure plant operation is maintained within the assumptions of the safety analyses. Large differences between monitored and predicted core reactivity may indicate that the assumptions of the DBA and transient analyses are no longer valid, or that the uncertainties in the Nuclear Design Methodology are larger than expected. A limit on the difference between the monitored core keff and the predicted core keff of 1% Ak/k has been established based on engineering judgment. A > 1%

deviation in reactivity from that predicted is larger than expected for normal operation and should therefore be evaluated.

APPLICABILITY In MODE 1, most of the control rods are withdrawn and steady state operation is typically achieved. Under these conditions, the comparison between predicted and monitored core reactivity provides an effective measure of the reactivity anomaly. In MODE 2, control rods are typically being withdrawn during a startup. In MODES 3 and 4, all control rods are fully inserted, and, therefore, the reactor is in the least reactive state, where monitoring core reactivity is not necessary. In MODE 5, fuel loading results in a continually changing core reactivity. SDM requirements (LCO 3.1.1) ensure that fuel movements are performed within the bounds of the safety analysis, and an SDM demonstration is required during the first startup following operations that could have altered core reactivity (e.g., fuel movement, control rod replacement, control rod shuffling). The SDM test, required by LCO 3.1.1, provides a direct comparison of the predicted and monitored core reactivity at cold conditions; therefore, reactivity anomaly is not required during these conditions.

ACTIONS A.1 Should an anomaly develop between measured and predicted core reactivity, the core reactivity difference must be restored to within the limit to ensure continued operation is within the core design assumptions. Restoration to within the limit could be performed by an evaluation of the core design and safety analysis to determine the reason for the anomaly. This evaluation normally reviews the core (continued)

CLINTON B 3.1i-10 Revision No. 14-5

Reactivity Anomalies B 3.1.2 BASES ACTIONS A.1 (continued) conditions to determine their consistency with input to design calculations. Measured core and process parameters are also normally evaluated to determine that they are within the bounds of the safety analysis, and safety analysis calculational models may be reviewed to verify that they are adequate for representation of the core conditions.

The required Completion Time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is based on the low probability of a DBA during this period, and allows sufficient time to assess the physical condition of the reactor and complete the evaluation of the core design and safety analysis.

B.1 If the core reactivity cannot be restored to within the 1% Ak/k limit, 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 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 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 3.1.2.1 REQUIREMENTS Verifying the reactivity difference between the monitored and predicted core keff is within the limits of the LCO provides further assurance that plant operation is maintained within the assumptions of the DBA and transient analyses. The Core Monitoring System calculates the core keff for the reactor conditions obtained from plant instrumentation. A comparison of the monitored core keff to the predicted core keff at the same cycle exposure is used to calculate the reactivity difference. The comparison is required when the core reactivity has potentially changed by a significant amount. This may occur following a refueling in which new fuel assemblies are loaded, fuel assemblies are shuffled within the core, or control rods are replaced or shuffled. Control rod replacement refers to the decoupling and removal of a control rod from a core location, and subsequent replacement with a new control rod (continued)

CLINTON B 3.1i-11 Revision No. 14-5

Reactivity Anomalies B 3.1.2 BASES SURVEILLANCE SR 3.1.2.1 (continued)

REQUIREMENTS or a control rod from another core location. Also, core reactivity changes during the cycle. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months interval after reaching equilibrium conditions following a startup is based on the need for equilibrium xenon concentrations in the core, such that an accurate comparison between the monitored and predicted core keff values can be made. For the purposes of this SR, the reactor is assumed to be at equilibrium conditions when steady state operations (no control rod movement) at Ž 80% RTP have been obtained for at least 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The 1000 MWD/T Frequency was developed, considering the relatively slow change in core reactivity with exposure and operating experience related to variations in core reactivity. This comparison requires the core to be operating at power levels which minimize the uncertainties and measurement errors, in order to obtain meaningful results. Therefore, the comparison is only done when in MODE 1.

With regard to core reactivity differences values obtained pursuant to this SR, as determined from plant indication instrumentation, the specified limit is considered to be a nominal value and therefore does not require compensation for instrument indication uncertainties (Ref. 3).

REFERENCES 1. 10 CFR 50, Appendix A, GDC 26, GDC 28, and GDC 29.

2. USAR, Chapter 15.

3. Calculation IP-0-0002.

CLINTON B 3. 1-12 Revision No. 14-5

EOC-RPT Instrumentation B 3.3.4.1 B 3.3 INSTRUMENTATION B 3.3.4.1 End of Cycle Recirculation Pump Trip (EOC-RPT) Instrumentation BASES BACKGROUND The EOC-RPT instrumentation initiates a recirculation pump trip (RPT) to reduce the peak reactor pressure and power resulting from turbine trip or generator load rejection transients to provide additional margin to core thermal MCPR Safety Limits (SLs).

The need for the additional negative reactivity in excess of that normally inserted on a scram reflects end of cycle reactivity considerations. Flux shapes at the end of cycle are such that the control rods may not be able to ensure that thermal limits are maintained by inserting sufficient negative reactivity during the first few feet of rod travel upon a scram caused by Turbine Control Valve (TCV) Fast, Closure, Trip Oil Pressure-Low, or Turbine Stop Valve (TSV)

Closure. The physical phenomenon involved is that the void reactivity feedback due to a pressurization transient can add positive reactivity at a faster rate than the control rods can add negative reactivity-The EOC-RPT instrumentation as described in Reference 1 is comprised of sensors that detect initiation of closure of the TSVs, or fast closure of the TCVs, combined with logic circuits, load drivers, and fast acting circuit breakers that interrupt the fast speed power supply to each of the recirculation pump motors. The channels consist of pressure switches and limit switches. When the setpoint is exceeded, the switch closes which then inputs a signal to the EOC-RPT trip logic. Actuation of the EOC-RPT system causes each division of the RPS to energize a trip coil in its associated RPT breaker. When the EOC-RPT breakers trip open, the safety function is completed. The recirculation pumps may coast to stop or downshift to slow speed.

Negative reactivity is provided in either case.

The EOC-RPT system is a two-out-of-four logic for each Function; thus, either two TSV Closure or two TCV Fast Closure, Trip Oil Pressure-Low signals are required to actuate tripping both recirculation pumps from fast speed operation. There are two EOC-RPT breakers in series per recirculation pump. A trip in Division 1 (or 4) will cause a trip of the 'A' recirculation pump. A trip in Division 2 (or 3) will cause a trip of the 'B' recirculation pump.

Both EOC-RPT breakers for each recirculation pump trip upon actuation of the EOC-RPT system. Placing an EOC-RPT bypass switch in "bypass" will allow the EOC-RPT trip capability to be maintained, however, an additional single failure cannot be accommodated (refer to Required Action B.l Bases).

(continued)

CLINTON B 3.3-65 Revision No. 14-5

U-604075, Transmittal of Revision 14 to the Technical Specification Bases

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