Text

Part a - Revisions 58 -76 to River Bend Station Technical Requirements Manual & Technical Specification Bases
	ML021050303
Person / Time
Site:	River Bend
Issue date:	04/10/2002
From:	King R; Entergy Operations
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	RBF1-02-0053, RBG-45935
	Download: ML021050303 (124)
	v • d • e

Entergy Operations, Inc.

River Bend Statio 5485 U.S. Highway 61 P. 0. Box 220 St. Francisville, LA 70775 En tergTet 225 336 6225 Fax 225 635 5068 Rick J. King Director Nuciear Safety Assurance April 10, 2002 U.S. Nuclear Regulatory Commission Document Control Desk Washington, D.C. 20555

Subject:

River Bend Station - Unit 1 Docket No. 50-45 8 License No. NPF-47 Revisions to the Technical Requirements Manual and the Technical Specifications Bases File Nos.:

G9.5, G9.25.1.5, G9.41.1 RBG-45935 RBF1-02-0053 Gentlemen:

Pursuant to 1 OCFR50.71 (e), Entergy Operations, Inc. (EOI) herein submits changes to the River Bend Station (RBS) Technical Requirements Manual (TRM). The revised pages cover changes made during the period from April 8, 2000, through April 1, 2002. This includes TRM revisions 58 through 76. A list of effective pages is included to identify the current pages of the TRM through revision 76.

Pursuant to RBS Technical Specification 5.5.11, revised pages for the Technical Specification Bases pages are included. The revised pages cover changes made from April 8, 2000, through April 1, 2002. This includes Bases revisions 6-1 through 6-15, and revisions 101 and 102. The method of numbering Bases revisions was recently changed to a numbering system similar to the TRM and Technical Specifications. A list of effective pages is included to identify the current pages of the Bases through Revision 102.

As required by 10CFR50.71 (e)(2)(i), the below affirmation certifies that the information in this submittal accurately reflects changes made since the previous submittal, necessary to represent information and analyses submitted or prepared pursuant to NRC requirements.

, 01

RBG-45935 RBF1-02-0053 Page 2 of 2 Should you have any questions, please advise Mr. J. W. Leavines at (225) 381-4642.

I declare under penalty of perjury that the foregoing is true and correct.

Executed on April 10, 2002.

R. J. King U

Director-Nuclear Safety Assurance RJK/DNL enclosures:

1) Technical Requirements Manual Revision Package

2) Technical Specification Bases Revision Package cc:

U.S. Nuclear Regulatory Commission Region IV 611 Ryan Plaza Drive, Suite 400 Arlington, TX 76011 U.S. Nuclear Regulatory Commission Senior Resident Inspector P.O. Box 1050 St. Francisville, LA 70775

TECHNICAL REQUIREMENTS MANUAL LIST OF EFFECTIVE PAGES PAGE NUMBER I REV iv iii V

vi TR 1-1 TR 1-2 TR 1-3 TR 1-4 TR 1-5 TR 1-6 TR 1-7 TR 1-8 TR 1-9 TR 1-10 TR 1-11 TR 1-12 TR 3.0-1 TR 3.0-2 TR 3.0-3 TR 3.0-4 TR 3.01-1 TR 3.1-1 TR 3.1-2 TR 3.1-3 TR 3.1-4 TR 3.2-1 TR 3.3-1 TR 3.3-2 TR 3.3-3 TR 3.3-4 TR 3.3-5 TR 3.3-6 TR 3.3-7 TR 3.3-8 TR 3.3-9 TR 3.3-10 TR 3.3-11 TR 3.3-12 TR 3.3-13 TR 3.3-14 TR 3.3-15 TR 3.3-16 TR 3.3-17 TR 3.3-18 TR 3.3-19 TR 3.3-20 PAGE NUMBER 62 67 62 5

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TECHNICAL REQUIREMENTS MANUAL LIST OF EFFECTIVE PAGES PAGE NUMBER I REV PAGE NUMBER

[ REV PAGE NUMBER I REV TR 3.6-7 (20iii) 57 TR 3.7-28 (15xxi) 58 TR3.11-6 18 TR 3.6-8 (20iv) 68 TR 3.7-29 (15xxii) 18 TR3.11-7 14 TR 3.6-9 (20v) 69 TR 3.7-30 (15xxiii) 5 TR 3.11-8 5

TR 3.6-10 (20vi) 57 TR 3.7-31 (15xxiv) 5 TR3.11-9 5

TR 3.6-11 (20vii) 69 TR 3.7-32 (15xxv) 18 TR3.11-10 75 TR 3.6-12 (22i) 12 TR 3.7-33 (15xxvi) 5 TR 3.11-11 5

TR 3.6-13 (28i) 35 TR 3.7-34 (15xxvii) 5 TR 3.11-12 5

TR 3.6-14 (28ii) 35 TR 3.7-35 (15xxviii) 5 TR 3.11-13 5

TR3.6-15 (30i) 5 TR3.8-1 (15i) 76 TR 3.11-14 5

TR 3.6-16 (35i) 5 TR 3.8-2 (5aii) 65 TR3.11-15 5

TR 3.6-17 (36i) 5 TR 3.8-3 (15iii) 76 TR 3.11-16 5

TR 3.6-18 (40i) 5 TR 3.8-4 (19i) 5 TR3.11-17 5

TR 3.6-19 (50i) 62 TR 3.8-5 (20i) 76 TR 3.12-1 5

TR 3.6-20 (52i) 63 TR 3.8-6 (23i) 64 TR 3.12-2 5

TR 3.6-21 (54i) 40 TR 3.8-7 (27i) 55 TR 3.12-3 41 TR 3.8-8 (42i) 50 TR 3.12-4 41 TR 3.6-23 (59i) 5 TR 3.8-9 (42ii) 5 TR 3.12-5 59 TR 3.6-24 (61i) 18 TR 3.8-10 (42iii) 5 TR 3.12-6 41 TR 3.6-25 (70i) 5 TR 3.8-11 (42iv) 5 TR 3.12-7 41 TR 3.6-26 (70ii) 59 TR 3.8-12 (42v) 5 TR 3.12-8 5

TR 3.6-27 (72i) 5 TR 3.8-13 (42vi) 59 TR 3.12-9 5

TR 3.7-1 (4i) 5 TR 3.8-14 (42vii) 5 TR 3.12-10 41 TR 3.7-2 (4ii) 5 TR 3.8-15 (42viii) 5 TR 3.12-11 41 TR 3.7-3 (4iii) 5 TR 3.8-16, (42ix) 74 TR 3.12-12 5

TR 3.7-4 (4iv) 5 TR 3.8-17 (42x) 74 TR 5-1 59 TR 3.7-5 (8i) 5 TR 3.8-18 (42xi) 30 TR 5-2 5

TR 3.7-6 (1 li) 26 TR 3.8-19 (42xii) 5 TR 5-3 5

TR 3.7-7 (14i) 5 TR 3.8-20 (42xiii) 5 TR 5-4 53 TR 3.7-8 (15i) 5 TR 3.8-21 (42xiv) 5 TR 5-5 65 TR 3.7-9 (15ii) 5 TR 3.8-22 (42xv) 30 TR 5-6 64 TR 3.7-10 (15iii) 5 TR 3.8-23 (42xvi) 31 TR5-7 23 TR 3.7-11 (15iv) 5 TR3.9-1 (7i) 5 TR5-8 5

TR 3.7-12 (15v) 5 TR 3.9-2 (7ii) 72 TR 5-9 5

TR 3.7-13 (15vi) 5 TR 3.9-3 (13i) 5 TR5-10 5

TR 3.7-14 (15vii) 15 TR 3.9-4 (13ii) 5 TR 5-11 5

TR 3.7-15 (15viii) 5 TR 3.9-5 (13iii) 70 TR 5-12 5

TR 3.7-16 (15ix) 5 TR 3.9-6 (13iv) 5 TR 5-13 36 TR 3.7-17 (15x) 58 TR 3.9-7 (13v) 5 TR 5-14 33 TR3.7-18

-- (15xi) 5 TR3.9-8 (13vi) 5 TR5-15 53 TR 3.7-19 (15xii) 58 TR 3.9-9 (13vii) 54 TR 5-16 53 TR 3.7-20 (15xih')

5 TR 3.9-10 (13viii) 56 TR 5-17 59 TR 3.7-21 (15xiv) 15 TR3.9-11 (13ix) 56 TR 5-18 53 TR 3.7-22 (15x'v) 58 TR3.9-12 (13x) 32 TR5-19 53 TR 3.7-23 (15xvi) 5 TR 3.11-1 15 TR 5-20 53 TR 3.7-24 (15xvii) 5 TR 3.11-2 5

TR 5-21 52 TR 3.7-25 (15xviii) 58 TR 3.11-3 5

TR 5-22 8

TR 3.7-26 (15xix) 5 TR 3.11-4 5

TR 3.7-27 (15xx) 5 TR 3.11-5 5

Revision 76 RIVER BEND TR-b

Spray and/or Sprinkler Systems TR 3.7.9.2 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY TSR 3.7.9.2.5 Perform a visual inspection of the dry 18 months pipe spray and sprinkler headers to verify their integrity.

TSR 3.7.9.2.6

NOTE-------------------

The charcoal filter system deluge area and header internal to the filter system need only be verified to be unobstructed by visual inspection each time the charcoal is changed.

18 months Perform a visual inspection of each deluge nozzle's spray area to verify that the spray pattern is not obstructed.

TSR 3.7.9.2.7

NOTE-------------------

Not applicable to charcoal filter systems.

The charcoal filter systems do not utilize nozzles.

Perform an air or water flow test through each open head spray and 3 years sprinkler system and verify that each open head spray nozzle is unobstructed.

RIVER BEND TR 3.7-17 Revision 58 (15x)

Halon Systems TR 3.7.9.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TSR 3.7.9.3.1.

(Deleted)

TSR 3.7.9.3.2. Verify Halon storage tank weight and 6 months pressure.

TSR 3.7.9.3.3 NOTE 18 months Actual Halon release and Halon bottle explosive initiator valve actuation may be excluded from the test Verify the system actuates, manually and automatically, upon receipt of a simulated actuation signal.

TSR 3.7.9.3.4 Perform a flow test through headers and 18 months nozzles to assure no blockage.

RIVER BEND Revision 58 TR 3.7-19 (15xii)

Fire Hose Stations TR 3.7.9.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TSR 3.7.9.4.1. Perform a visual inspection of the fire 31 days hose stations accessible during plant operation to assure all required equipment is at the station.

TSR 3.7.9.4.2 Perform a visual inspection of the fire 18 months hose stations not accessible during plant operation to assure all required equipment is at the station.

TSR 3.7.9.4.3 Remove the hose for inspection and re-18 months racking, and inspect all gaskets and replace any degraded gaskets in the couplings.

TSR 3.7.9.4.4 Partially open each hose station valve to 3 years verify valve OPERABILITY and no flow blockage.

TSR 3.7.9.4.5 Remove the hose for hydrostatic testing.

3 years Perform a Service Test on all in-service hose at a pressure of 150 psig or at least 50 psig above the maximum fire main operating pressure, whichever is greater, to determine suitability for continued service.

Any hose failing the service test shall be replaced with hose that has had a successful Service Test performed.

RIVER BEND TR 3.7-22 (15xv)

Revision 58

Yard Fire Hydrants and Hydrant Hose Houses TR 3.7.9.5 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TSR 3.7.9.5.1. Perform a visual inspection of the hydrant 31 days hose house to assure all required equipment is at the hose house.

TSR 3.7.9.5.2. Visually inspect each yard fire hydrant and 184 days verify that the hydrant barrel is properly drained and that the hydrant is not damaged.

TSR 3.7.9.5.3 Remove each hose for hydrostatic testing.

12 months Perform a Service Test on all inservice hose at a pressure of 150 psig or at least 50 psig above the maximum fire main operating pressure, whichever is

greater, to determine suitability for continued service.

Any hose failing the service test shall be replaced with hose that has had a successful Service Test performed.

TSR 3.7.9.5.4 Replace all degraded gaskets in couplings.

12 months TSR 3.7.9.5.5 Perform a flow check of each hydrant.

12 months RIVER BEND Revision 58 TR 3.7-25 (15xviii)

Fire-Rated Assemblies TR 3.7.9.6 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TSR 3.7.9.6.1 Verify that doors with automatic hold open 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months and release mechanisms are free of obstructions.

TSR 3.7.9.6.2 Verify that each unlocked fire door without 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months electrical supervision is closed.

TSR 3.7.9.6.3 Verify that each locked-closed fire door is 7 days closed.

TSR 3.7.9.6.4 Verify the OPERABILITY of the fire door 31 days supervision system for each electrically supervised fire door by performing a CHANNEL FUNCTIONAL TEST.

TSR 3.7.9.6.5 Perform a visual inspection of the 184 days automatic hold open, release and closing mechanisms and latches on all required fire doors utilizing automatic hold open and release mechanisms (held open fire doors).

TSR 3.7.9.6.6 Perform a visual inspection of the exposed 18 months surfaces of each fire-rated assembly.

TSR 3.7.9.6.7 Perform a visual inspection of each fire 18 months damper and associated hardware.

TSR 3.7.9.6.8 Perform a visual inspection of at least 18 months 10 percent of each type of sealed penetration.

If changes in appearance or abnormal degradations are found, a visual inspection of an additional 10 percent of each type of sealed penetration where changes in appearance or abnormal degradation was noted shall be made.

This inspection process shall continue until a 10 percent sample of each type of sealed penetration is found with no apparent changes in appearance or abnormal degradation.

Samples shall be selected such that each penetration seal will be inspected at least once per 15 years.

TSR 3.7.9.6.9 Perform a functional test of the 18 months automatic hold-open, release and closing mechanism and latches.

RIVER BEND TR 3.7-28 (15xxi)

Revision 58

Traversing In-core Probe System TR 3.3.7.7 TR 3.3.7.7 Traversing In-core Probe System TLCO 3.3.7.7 APPLICABILITY:

The traversing in-core probe system shall be OPERABLE with:

a.

Three movable detectors, drives and readout equipment to map the core,

b.

Indexing equipment to allow all available detectors to be intercalibrated in the common tube, and

c.

Twenty-five scannable nuclear instrument tubes, including the common tube.

When the traversing in-core probe is used for recalibration of the LPRM detectors.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

The traversing in-core A.1 Do not use the system for Immediately probe system inoperable, the above applicable monitoring or calibration.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TSR 3.3.7.7.1

NOTE--------------------

Only required to be met during use for LPRM calibration.

Normalizing each of the above required detector Within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months outputs.

prior to use for LPRM calibration.

RIVER BEND TR 3.3-66 (71xix)

Revision 59

Drywell Isolation Valves TR 3.6.5.3 TABLE 3.6.5.3-1 (page 2 of 2)

DRYWELL ISOLATION VALVES (continued)

SY.STEM VALVE PENETRATION NUMBER NUMBER C.

Other loaItion Valves (continued)

Main Steam SRV Disch.

LPCI A to Reactor LPCI B to Reactor Reactor Bldg.

Floor Drain Hdr.

Reactor Bldg.

Floor Drain Hdr.

Reactor Bldg.

Floor Drain Hdr.

Reactor Bldg. Floor Drain Hdr.

Reactor Bldg.

Equip. Drain Hdr.

Reactor Bldg. Equip. Drain Hdr.

Service Air Supply Instr. Air Supply RPCCW Supply Service Water Supply Service Water Return SLCS Injection SLCS Injection SLCS Injection SLCS Injection RPCCW Return Air Sup. for Main Steam SRV Air Sup. for Main Steam SRV Air Sup. for Main Steam SRV Air Sup. for Main Steam SRV Air Sup. for Main Steam SRV Air Sup. for Main Steam SRV Air Sup. for Main Steam SRV Air Sup. for Main Steam SRV Air Sup. for Main Steam SRV Air Sup. for Main Steam SRV Air Sup. for Main Steam SRV Air Sup. for Main Steam SRV Air Sup. for Main Steam SRV Air Sup. for Main Steam SRV Air Sup. for Main Steam SRV Air Sup. for Main Steam SRV Recirc. Pump Seal Water Sup.

Recirc.

Pump Seal Water Sup.

Recirc.

Pump SeaL Water Sup.

Recirc.

Pump Seal Water Sup.

1B21*RVF041G 1821*RVF051C 1B21*RVF041C 1B21*RVFO47B 1B21*RVF041B 1B21*RVF051B 1B21*RVFO41F 1821*RVF047F 1B21*RVF041D 1B21*RVF047D 1B21*RVF051D 1E12*AOVFO41A(a) 1E12*AOVFO41B(a) 1DFR*V4 1DFR*V3 1DFR*V1 1DFR*V2 1DER*V14 1DER*V15 1DER*V16 1DER*V17 1SAS*V487 1IAS*V78 ICCP*V119 1SWP*RV119 1SWP*RV140 1C41*VEXF004A 1C41*VEXFCC4B IC41*VF006 1C41*VF007 1CCP*V133 1B21*VFO36A 1821*VF036F 1B21*VF036G 1B21*VFO36P 1821*VF039C 1B21*VFO39H 1B21*VFO39K 1821*VF039S 1821*VFO36J 1B21*VF036L 1B21*VF036M 1B21*VF036N 1B21*VFO36R 1B21*VF039B 1B21*VF039D 1B21*VFO39E 1833*VFO13A 1B33*VFO17A 1833*VFO13B 1B33*VFO17B (a)

Testable check valve.

(b)

Receives a remote manual isolation signal.

(c)

Valve groups are designated in Table 3.3.6.1-2 RIVER BEND TR 3.6-26 (70ii)

Revision 59 1DRB*Z141 1DRB*Z142 1DRB*Z143 1DRB*Z144 1DRB*Z145 1DRB*Z146 1DRB*Z147 1DRB*Z148 1DRB*Z149 1DRB*Z150 1DRB*Z151 1DRB*Z22A 1DRB*Z22B 1DRB*Z37A 1DRB*Z37A 1DRB*Z37B 1DRB*Z37B 1DRB*Z40A 1DRB*Z40A 1DRB*Z40B 1DRB*Z40B 1DRB*Z45 1DRB*Z47 1DRB*Z50 1DRB*Z54 1DRB*Z55 1DRB*Z56 1DRB*Z56 1DRB*Z56 1DRB*Z56 1DRB*Z51 1DRB*Z107 1DRB*Z107 1DRB*ZI07 1DRB*Z107 1DRB*Z107 1DRB*Z107 1DRB*Z107 1DRB*Z107 1DRB*Z112 1DRB*Z112 1DRB*Z112 1DRB*Z1 12 1DRB*Z112 1DRB*Z1 12 1DRB*Z112 1DRB*Z112 1DRB*Z133 1DRB*Z133 1DRB*Z135 1DRB*Z135

Electrical Equipment Protective Devices TR 3.8.11 TABLE 3.8.11-1 (page 2 of 7)

PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTION DEVICES

1.

Type Square D (continued)

PRIMARY PROTECTION Location 1LAR-BKRIB 1LAR-BKR2B 1LAR-BKR3B 1LAR-BKR4B 1LAR-BKR5B 1LAR-BKR6B 1LAR-BKR7B 1LAR-BKR8B 1LAR-BKR9B iLAR-BKR1OB 1LAR-BKR11B 1LAR-BKR12B ILAR-BKRI3B 1LAR-BKR14B ILAR-BKRI6B 1LAR-BKR17B 1LAR-BKR18B 1LAR-BKR19B 1SCA-BKR2A12 ISCA-BKR2D12 ISCA-BKR2F12 1SCA-BKR2D14 1SCA-BKR8A22 1SCA-BKR8B22 lHTS*BKR2M-1 1HTS*BKR2M-2 1IHTS*BKR2M-3 1HTS*BKR2M-4 1HTS*BKR2M-7 lHTS*BKR2M-8 IHTS*BKR2M-9 IHTS*BKR2N-1 IHTS*BKR2N-2 lHTS*BKR2N-5 IHTS*BKR2N-6 IHTS-BKRIN-15 SCV-PNL2B1-5(Branch)

SECONDARY PROTECTION EQUIP.

NO.

Location 1LAR-BKR1A 1LAR-BKR2A 1LAR-BKR3A 1LAR-BKR4A 1LAR-BKR5A 1LAR-BKR6A 1LAR-BKR7A 1LAR-BKR8A 1LAR-BKR9A 1LAR-BKR1OA 1LAR-BKR1IA 1LAR-BKR12A ILAR-BKRI3A lLAR-BKR14A 1LAR-BKR16A 1LAR-BKR17A 1LAR-BKR18A 1LAR-BKR19A 1SCA-BKR2A1I 1SCA-BKR2DII 1SCA-BKR2F1I 1SCA-BKR2D13 1SCA-BKR8A21 1SCA-BKRBB21 SCV-PNL2BI-M(Main) 1LAR-PNLIRI 1LAR-PNL1R2 1LAR-PNL1R3 1LAR-PNL1R4 1LAR-PNL1R5 1LAR-PNLIR6 1LAR-PNL1R7 1LAR-PNL1R8 1LAR-PNLIR9 1LAR-PNL1R10 1LAR-PNL1RII 1LAR-PNL1R12 1LAR-PNL1R13 1LAR-PNL1R14 1LAR-PNLIR16 1LAR-PNL1R17 1LAR-PNLIRI8 1LAR-PNL1R19 1SCA-PNL2A1 1SCA-PNL2DI 1SCA-PNL2F2 1SCA-PNL2D3 1SCA-PNL8A2 1SCA-PNL8B2 1HTS*PNL2M 1HTS*PNL2M 1HTS*PNL2M 1HTS*PNL2M 1HTS*PNL2M 1HTS*PNL2M IHTS*PNL2M 1HTS*PNL2N 1HTS*PNL2N 1HTS*PNL2N IHTS*PNL2N lHTS-PNLIN SCV*PNL2B1 (continued)

RIVER BEND TR 3.8-13 (42vi)

Revision 59

Monitoring Program TR 3.12.1 TABLE 3.12.1-1 (page 3 of 4)

RADIOLOGICAL ENVIRONMENTAL MONITORING PROGRAM a

The ODCM shall include, in a table and figures, specific parameters of distance and direction sector from the centerline of one reactor, and additional description where pertinent, for each sample location in Table 3.12.1-1.

Refer to NUREG-0133, "Preparation of Radiological Effluent Technical Specifications for Nuclear Power Plants,"

October 1978, and to Radiological Assessment Branch Technical Position, Revision 1, November 1979.

Deviations are permitted from the required sampling schedule if specimens are unobtainable due to hazardous conditions, seasonal unavailability, malfunction of automatic sampling equipment, or other legitimate reasons.

If specimens are unobtainable due to sampling equipment malfunction, every effort shall be made to complete corrective action prior to the end of the next sampling period.

All deviations from the sampling schedule shall be documented in the Annual Radiological Environmental Operating Report pursuant to Technical Specification 5.6.2.

It is recognized that, at times, it may not be possible or practicable to continue to obtain samples of the media of choice at the most desired location or time.

In these instances suitable alternative media and locations may be chosen for the particular pathway in question and appropriate substitutions made within 30 days in the radiological environmental monitoring program.

In the next Annual Radioactive Effluent Release Report, pursuant to Technical Specification 5.6.3, identify the cause of the unavailability of samples for that pathway and identify the new location(s) for obtaining replacement samples, and also include in the report a revised figure(s) and table for the ODCM reflecting the new location(s).

b -

One or more instruments, such as a pressurized ion chamber, for measuring and recording dose rate continuously may be used in place of, or in addition to, integrating dosimeters.

For the purposes of this table, a thermoluminescent dosimeter (TLD) is considered to be one phosphor; two or more phosphors in a packet are considered as two or more dosimeters.

Film badges shall not be used as dosimeters for measuring direct radiation.

The 24 stations is not an absolute number.

The number of direct radiation monitoring stations may be reduced according to geographical limitations; e.g., at an ocean site, some sectors will be over water so that the number of dosimeters may be reduced accordingly.

The frequency of analysis or readout for TLD systems will depend upon the characteristics of the specific system used and should be selected to obtain optimum dose information with minimal fading.

c The purpose of this sample is to obtain background information.

If it is not practical to establish control locations in accordance with the distance and wind direction criteria, other sites that provide valid background data may be substituted.

Revision 59 TR 3. 12-5 RIVER BEND

ADMINISTRATION TR 5.0 TR 5.0 ADMINISTRATIVE CONTROLS TR 5.1 Responsibility TR 5.1.1 (Not used)

TR 5.1.2 A management directive restating the Technical Specification 5.1.2 Control Room command function requirements signed by the Vice President-RBS shall be issued to all station personnel on an annual basis.

TR 5.2 Organization TR 5.2.1 Plant Specific Titles The following are the plant specific titles for the personnel fulfilling responsibilities of positions delineated in Technical Specifications:

a.

The corporate executive responsible for overall plant nuclear safety is Vice President-River Bend Station (RBS).

b.

The Plant manager is the General Manager.

c.

The shift superintendent is the Shift Manager.

d.

A non-licensed operator is a Nuclear Equipment Operator.

e.

The operations manager is the Manager -

Operations.

f.

The operations middle manager is the Assistant Operations Manager.

g.

The radiation protection manager is the Superintendent Radiation Protection.

h.

A health physics technician is an individual qualified as a Radiation Protection Technician.

i.

Health Physics supervision is Radiation Protection personnel, Supervisor and above.

Revision 59 TR 5-1 RIVER BEND

ADMINISTRATION TR 5.0 TR 5.3 Unit Staff Qualifications TR 5.3.1 Licensed Operator Qualifications The licensed Operators and Senior Operators shall also meet or exceed the minimum qualifications of ANSI/ANS 3.1-1978.

TR 5.3.2 Licensed Operator Training A retraining and replacement training program for the unit staff shall be maintained under the direction of the Manager-Training and Emergency Preparedness and shall meet the requirements of 10 CFR Part 55 and shall include familiarization with relevant industry operational experience.

TR 5.3.3 Unit Staff Training Other than for Licensed Operators, a retraining and replacement training program for unit staff shall be maintained under the direction of the Manager-Training and Emergency Preparedness and shall meet or exceed the recommendations of ANSI/ANS 3.1-1978 and shall include familiarization with relevant industry operational experience.

Revision 59 RIVER BEND TR 5-5

ADMINISTRATION TR 5.0 TR 5.4 Procedures TR 5.4.1 Written procedures shall be established, implemented, and maintained covering the activities referenced below:

a.

The applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978.

b.

The emergency operating procedures required to implement the requirements of NUREG-0737 and supplements thereto.

c.

Refueling operations.

d.

Surveillance and test activities of safety-related equipment.

e.

Security Plan implementation.

f.

Emergency Plan implementation.

g.

Fire Protection Program implementation.

h.

Process Control Program implementation.

i.

Offsite Dose Calculation Manual implementation.

j.

Quality Assurance Program for effluent and environmental monitoring.

k.

Technical Requirements Manual implementation.

1.

Technical Specifications Bases Control Program implementation.

TR 5.4.2 Each procedure of Requirement 5.4.1, and changes thereto, shall be reviewed and approved in accordance with Requirement 5.8.2.1.

TR 5.4.3 Temporary changes to procedures of Requirement 5.4.1 may be made provided:

a.

The intent of the original procedure is not altered;

b.

The change is approved by two members of the plant management staff, at least one of whom holds a Senior Operator license on the unit affected; and

c.

The change is documented, reviewed by the FRC as required by Requirement 5.8.1.6, and approved in accordance with Requirement 5.8.2.1 within 14 days of implementation.

TR 5.4.4 Procedures may use either the plant specific title listed in Technical Requirement 5.2.1 or the generic Technical Specification title when identifying a person fulfilling the responsibilities of a position delineated in Technical Specifications.

RIVER BEND Revision 59 TR 5-6

ADMINISTRATION TR 5.0 TR 5.8.2 Technical Review and Control TR 5.8.2.1 TR 5.8.2.2 TR 5.8.2.3 TR 5.8.2.4 TR 5.8.2.5 TR 5.8.2.6 Each procedure and program required by Technical Specifications 5.4, 5.5, and other procedures that affect nuclear safety, and changes thereto, is prepared by a qualified individual/organization.

Each such procedure, and changes thereto, shall be reviewed by an individual/group other than the individual/group that prepared the procedure, or changes thereto, but who may be from the same organization as the individual/group that prepared the procedure.

Each such procedure and program, or changes thereto, shall be approved, prior to implementation, by the plant manager, or the Superintendent - Radiation Protection, or the manager/department head responsible for the program or the activity described in the procedure.

Individuals responsible for reviews performed in accordance with Section TR 5.8.2.1 shall be members of River Bend Station supervisory staff, and the reviews shall be performed in accordance with administrative procedures.

Each such review shall include a determination of whether or not additional, cross disciplinary review is necessary and a verification that the proposed actions do not constitute an unreviewed safety question.

If deemed necessary, such review shall be performed by the appropriate designated review personnel.

The station security program and implementing procedures shall be reviewed at least once per 12 months, and recommended changes approved in accordance with Requirement 5.8.2.1.

The station emergency plan and implementing procedures and recommended changes shall be approved in accordance with Requirement 5.8.2.1.

The station fire protection plan and implementing procedures shall be reviewed at least once per 12 months, and recommended changes approved in accordance with Requirement 5.8.2.1.

The station Technical Requirements Manual and implementing procedures and recommended changes shall be approved in accordance with Requirement 5.8.2.1.

RIVER BEND Revision 59 TR 5-17

RPS instrumentation TR 3.3.1.1 Table 3.3.1.1-1 (page 3 of 3)

Reactor Protection System Instrumentation FUNCTION APPLICABLE REQUIRED CONDITIONS SURVEILLANCE NOMINAL SETP"INT/

MODES OR CHANNELS REFERENCED REQUIREMENTS RESPONSE TIME OTHER PER TRIP FROM SPECIFIED SYSTEM REQUIRED CONDITIONS ACTION D.1 1,2 H

SR SR SR SR SR SR SR SR SR SR 3.3.1.1.1 3.3.1.1.9 3.3.1.1.10 3.3.1.1.13 3.3.1.1.15 3.3.1.1.1 3.3.1.1.9 3.3.1.1.10 3.3. 1.1.13 3.3.1.1.15 49 inches 49 inches

9.

S Tram nmsc7.arge ".o/pme Water

' eve I-n Igh

a.

Transmit!ter/Trip Unit 5 (a) 2

0. Float Switch 1,2 H

SR 3.3.1.1.9 SR 3.3.1.1.13 SR 3.3.1.1.15 5 (a)

3.

Turbine Stop Valve Closure i0.

Turbine Control Valve Fast Closure, Trip Oil Pressure-Low SR 3.3:1.1.9 SR 3.3.1.1.13 SR 3.3.1.1.15 Z 40% RTP Z 40% RTP E

SR SR SR SR SR TSR SR 2

SR SR SR SR SR TSR SR 3.3.1.1.9 3.3.1.1.10 3.3.1.1.13 3.3.1.1.15 3.3.1.1.16 3.3.1.1.16 3.3.1.1.18 3.3.1.1.9 3.3.1.1.10 3.3.1.1.13 3.3.1.1.15 3.3.1.1.16 3.3.1.1.16 3.3.1.1.18 47.32 inches for LSN013A, B

45.44 inches for LSNO13C, D

47.32 inches for LSNO13A, B

45.44 inches for LSN013C, D

5% closed (g)

S 0.06 sec 530 psig

)g) 5 0.07 secýf:

11. Reactor Mode Switch Shutdown Position

12. Manual Scram 1,2 5 (a) 1,2 5 (a) 2 H

SR 3.3.1.1.12 SR 3.3.1.1.15 2

2 SR 3.3.1.1.12 SR 3.3.1.1.15 SR 3.3.1.1.5 SR 3.3.1.1.15 SR 3.3.1.1.5 SR 3.3.1.1.15 2

NA NA NA NA (a) With any control rod withdrawn from a core cell containing one or more fuel assemblies.

'b, (c),

(d),

(e),

(h) not used this page

f)

Measured from start of turbine control valve fast closure.

ýg) The Turbine First Stage Pressure nominal setoint is 188 psig with an Allowable value 5 198.4 psig.

RIVER BEND TR 3.3-4 Revision 61 (9iii)

Control Rod Block Instrumentation TR 3.3.2.1 Table 3.3.2.1-1(Page 1 of 2)

Control Rod Block Instrumentation FUNCTION APPLICABLE REQUIRED CONDITIONS SURVEILLANCE NOMINAL ALLCWý MODES OR OTHER CHANNELS REFERENCED FROM REQUIREMENTS SETPOINT VALI SPECIFIED PER TRIP TLCO REQUIRED CONDITIONS FUNCTION ACTION A.!

1.Rod Pattern Control System

a.

Rod withdrawal iimlter J.

Rod pattern controller (a)

(b) 1(c), 2 2

2 ENTER SR 3.3.2.1.1 SR 3.3.2.1.6 LCO 3.3.2.1 SR 3.3.2.1.9 TSR 3.3.2.1.7 TSR 3.3.2.1.10 SR 3.3.2.1.2 SR 3.3.2.1,5 SR 3.3.2.1.7 SR 3.3.2.1.9 TSR 3.3.2.1.10 ENTER SR SR LCO 3.3.2.1 SR SR SR 3.3.2.1.3 3.3.2.1.4 3.3.2.1.5 3.3.2.1.7 3.3.2.1.9 2.Reactor Mode Switch Shutdown Position 3.Low Power Setpoint 4.Righ Power Setpoint 5.Average Power Range

a.

Flow Biased Neutron Flux -

High (d) 2 (b), (c),2

> HPSP 1

2 6

6 1,2

b.

Inoperative

c.

Downscale ENTER LCO 3.3.2.1 ENTER LCO 3.3.2.1 ENTER LCO 3.3.2.1 B

TSR TSR TSR TSR SR 3.3.2.1.8 TSR 3.3.2.1.11 TSR 3.3.2.1.11 27.5 +/- 3%

27. 5 2:

RTP RTP 67.9% RT?

5 6K..% R 3.3.2.1.13 3.3.2.1.14 3.3.2.1.16 3.3.2.1.18 8

TSR 3.3.2.1.13 TSR 3.3.2.1.14 TSR 3.3.2.1.13 TSR 3.3.2.1.14 TSR 3.3.2.1.16

d.

Neutron Flux -

High, Setdown 2

6 B

TSR 3.3.2.1.13 TSR 3.3.2.1.14 TSR 3.3.2.1.16 NA 5% RTP 12% RTP NA

Ž3% RTP 514% RT?

(continued)

RIVER BEND TR 3.3-10 (18i)

Revision 61

Control Rod Block Instrumentation TR 3.3.2.1 Table 3.3.2.1-1(Page 2 of 2)

Control Rod Block Instrumentation FUNCTION APPLICABLE REQUIRED CONDITIONS SURVEILLANCE NOMINAL AL LOWABLE MODES OR OTHER CHANNELS REFERENCED FROM REQUIREMENTS SETPOINT VALUE SPECIFIED PER TRIP TLCO REQUIRED CONDITIONS FUNCTION ACTION A.1 6.Source Range Monitors

a.

Detector not full in")

2 3

B TSR 3.3.2.1.12 NA NA TSR 3.3.2.1.16 5ý 2-C TSR 3.3.2.1.12 NA NA TSR 3.3.2.1.16

b.

Upscale"'

2 3

B TSR 3.3.2.1.12 1 x 10Sops S 1.6 x TSR 3.3.2.1.16 10cps 5ý 2-C TSR 3.3.2.1.12 1 x 10Sops

< 1.6 x TSR 3.3.2.1.16 i0Scos

c.

Inoperative"'

2 3

B TSR 3.3.2.1.12 NA NA 5

2**

C TSR 3.3.2.1.12 NA NA

d.

Downscale"'

2 3

B TSR 3.3.2.1.12

Ž0.7 cps",)

5 0.5 cpsý"

TSR 3.3.2.1.16 5'

2-C TSR 3.3.2.1.12

Ž0.7 cpsi"

> 0.5 cps"'

TSR 3.3.2.1.16 7.Intermediate Range Monitors

a.

Detector not full in 2,

5*

6 B

TSR 3.3.2.1.12 NA NA

b.

Upscale 2,

5-6 B

TSR 3.3.2.1.12 108/125

110/125 TSR 3.3.2.1.16 division of division of full scale full scale

c.

Inoperative 2,

5*

6 B

TSR 3.3.2.1.12 NA NA

d.

Downscale Ih 2,

5*

6 8

TSR 3.3.2.1.12 5/125

> 3/125 TSR 3.3.2.1.16 division of division of full scale full scale 8.Scram Discharge Volume

1. 2, 5*

2 D

TSR 3.3.2.1.13 Water level-high TSR 3.3.2.1.15 TSR 3.3.2.1.17

a. LISN602A 18.00" 5 21.12"

b.

LISN602B 18.00" 5 21.60" 9.Reactor Coolant System 1

2 D

TSR 3.3.2.1.13 114% of

117% of Recirculation Flow TSR 3.3.2.1.14 rated flow rated flow Upscale TSR 3.3.2.1.16 TSR 3.3.2.1.18 With any control rod withdrawn.

Not applicable to control rods removed per Technical Specification LCO 3.10.q or 3.10.6.

OPERABLE channels must be associated with SRM required OPERABLE per Technical Specification LCO 3.3.1.2.

(a)

THERMAL POWER > HPSP.

ob)

THERMAL POWER > 35% RTP and S HPSP.

(c)

With THERMAL POWER 5 20% RTP.

(d)

Reactor mode switch in the shutdown position.

(e)

This function is not required if detector count rate is Ž 100 cps or the IRM channels are on range 3 or higher.

(f)

This function is not required when the associated IRM channels are on range 8 or higher.

(g)

This function is not required when the IRM channels are on range 3 or higher.

(h)

This function is not required when the IRM channels are on range 1.

(i)

Provided the Signal to noise ratio is 5 2,0, otherwise trip setpoint of Ž3.0 cpa and allowable Ž1.8 cps.

(j)

Allowable Values and Nominal Values specified in COLR.

Allowable and nominal value modifications required by the COLR due to reduction in feedwater temperature may be delayed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

The trip setting for this Function must be maintained in accordance with TLCO 3.2.4.

(k)

To address feedwater temperature reductions, set at first stage turbine pressure equivalent to 61.03 % RT?.

RIVER BEND Revision 61 TR 3.3-11 (18ii)

EOC-RPT Instrumentation TR 3.3.4.1 TR 3.3.4.1 End of Cycle Recirculation Pump Trip (EOC-RPT)

Instrumentation

NOT The following surveillance requirement applies to Technical Specification LCO 3.3.4.1.

Failure to meet this surveillance requirement requires entry into Technical Specification LCO 3.3.4.1.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TSR 3.3.4.1.1 -

3.3.4.1.8 (Not Used)

TSR 3.3.4.1.9 Verify that all bypass valves are closed when 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

> 40% RTP with any recirc pump in fast speed.

TABLE 3.3.4.1-1 END OF CYCLE RECIRCULATION PUMP TRIP INSTRUMENTATION FUNCTION NOMINAL ALLOWABLE

RESPONSE

SETPOINT VALUE TIME a.Turbine Stop Valve Closure 5% closed S 7% closed

< 140 milliseconds

b. Turbine Control Valve Fast 530 psig

> 465 psig

< 140 closure

milliseconds Automatic bypass Turbine First Stage Pressure nominal setpoint is 188.2 psig with an allowable value of

194.7 psig.

RIVER BEND TR 3.3-16 Revision 61 (281)

INSTRUMENTATION

crimary Containment and Drywell Isolation Instrumentation TR 3.3.6.1 Table 3.3.6.1-I

{page 1 of 5)

Primary Containment and Drywell Isolation Instrumentation FUJNCTION APPLICABLE REQUTIRE

i.

Main Steam Line :sc-aticn

a.

Reactor- *Vessel! Water Level - Lzw L-w Low, Level 1 C.

Main Steam Line Pressure

- Low Main Steam Line wliw HIgh CHANNELS PER TRIP SYSTEM 2 per MSL REFERENCED FROM REQUIRED ACTION C.1 D

SR SR SR SR SR SR E

SR SR SR SR SR SR D

SR SR SR SR SR SURVEILLANCE REQUIREMENTS 3.3.6.1.1 3.3.6.1.2 3.3.6.1.3 3.3.6.1.5 3.3.6.1.6 3.3.6.1.7 3.3.6.1.1 3.3.6.1.2 3.3.6.i.3 3.3.6.1.5 3.3.6.1.6 3.3.6.1.7 3.3.6.1.1 3.3.6.1.2 3.3.6.1.3 3.3.6.1.5 3.3.6.1.6 NUMIN AL SETPO:NT!

RESPONSE TIME

-143 inches TL<_I. 0 3'9 849 psig T,<1. O (g) i85 psid, Line A 189 psid, Line B, C and D SR 3.3.6.1.7

d.

Condenser Vacuum - Low 2 ýa) 2 3 (a)

.Main Steam Tunnel emnperature - High

f.

Main Steam Tunnel Area Temperature - High 'El.

95ft)

g.

Main Steam Tunnel Area Temperature - High (El.

114ft!

1,2,3 1,2,3 1,2,3 2

2 D

SR SR SR SR SR D

SR SR SR SR D

SR SR SR SR SR D

SR SR SR SR SR 3.3.6.1.1 3.3.6.1.2 3.3.6.1.3 3.3.6.1.5 3.3.6.1.6 3.3.6.1.1 3.3.6.1.2 3.3.6.1.5 3.3.6.1.6 3.3.6.1.1 3.3.6.1.2 3.3.6.1.3 3.3.6.1.5 3.3.6.1.6 3.3.6.1.1 3.3.6.1.2 3.3.6.1.3 3.3.6.1.5 3.3.6.1.6 TL 50.5 (g) 8.5 inches Hg vacuum 141°F 142*F 142*F (continued, a:

With any turbine stop valve not closed.

, (d),

e), (f Not used this page.

7L Tx + TC; where:

TL= Measured total response time of the isolation system instrumentation x= Hydraulic response time of the channel sensor measured upon initial installation Tc Measured response time of the logic circuit excluding the channel sensor The given numerical value is the acceptance criterion for TL.

Isolation system instrumentation response time for only; no diesel generator delays are assumed.

TL shall be added to the 5-second isolation time shown in Table 3.6.1.3-1 for the MSIVs to obtain ISOLATION SYSTEM RESPONSE TIME for the MSIVs.

in case the sensor is replaced or refurbished, a hydraulic response time test must be performed to establish revised value for Tx.

RIVER BEND TR 3.3-32 (57i)

Revision 61 MODES OR OTHER SPECIFIED CONDITIONS 1,2,3 2

ý!S[iVs

TECHNICAL REQUIREMENTS MANUAL TABLE OF CONTENTS TR 1.0 USE AND APPLICATION TR 1-1 TR 1.1 Definitions TR 1-2 TR 2.0 SAFETY LIMITS (SLs)

(Not Used)

TR 3.0 LIMITING CONDITION FOR OPERATION (TLCO) APPLICABILITY TR 3.0-1 TR 3.0 SURVEILLANCE REQUIREMENT (TSR) APPLICABILITY TR 3.0-3 TR 3.1 REACTIVITY CONTROL SYSTEMS TR 3.1.1 (Not Used)

TR 3.1.2 (Not Used)

TR 3.1.3 Control Rod Operability TR 3.1-1 TR 3.1.4 (Not Used)

TR 3.1.5 Control Rod Scram Accumulators TR 3.1-2 TR 3.1.5.1 Control Rod Scram Accumulator Detectors/alarm Instrumentation TR 3.1-3 TR 3.1.6 (Not Used)

TR 3.1.7 (Not Used)

TR 3.1.8 (Not Used)

TR 3.1.9 Control Rod Drive Housing Support TR 3.1-4 TR 3.2 POWER DISTRIBUTION LIMITS TR 3.2.5 Main Turbine Pressure Regulation System TR 3.2-1 TR 3.3 INSTRUMENTATION TR 3.3.1.1 Reactor Protection System (RPS) Instrumentation TR 3.3-1 TR 3.3.1.2 (Not Used)

TR 3.3.2.1 Control Rod Block Instrumentation TR 3.3-5 TR 3.3.3.1 (Not Used)

TR 3.3.3.2 Remote Shutdown System TR 3.3-12 TR 3.3.4.1 End of Cycle Recirculation Pump Trip (EOC-RPT)Instrumentation TR 3.3-16 TR 3.3.4.2 ATWS Recirculation Pump Trip (ATWS-RPT) Instrumentation TR 3.3-17 TR 3.3.5.1 Emergency Core Cooling System (ECCS) Instrumentation TR 3.3-18 TR 3.3.5.1.1 Emergency Core Cooling System (ECCS) ADS Inhibit Instrumentation TR 3.3-24 TR 3.3.5.2 Reactor Core Isolation Cooling (RCIC) System Instrumentation TR 3.3-26 TR 3.3.6.1 Primary Containment and Drywell Isolation Instrumentation TR 3.3-27 TR 3.3.6.2 Secondary Containment and Fuel Building Isolation Instrumentation TR 3.3-40 TR 3.3.6.3 Containment Unit Cooler System Instrumentation TR 3.3-44 TR 3.3.6.4 Relief and Low-Low Set (LLS) Instrumentation TR 3.3-45 TR 3.3.6.4.1 Relief and Low-Low Set (LLS) Acoustic Monitor Instrumentation TR 3.3-46 Revision 62 I RIVER BEND TR-i

TECHNICAL REQUIREMENTS MANUAL TABLE OF CONTENTS TR 3.6 CONTAINMENT SYSTEMS TR 3.6.1.1 Primary Containment - Operating TR 3.6-1 TR 3.6.1.2 Primary Containment Air Locks TR 3.6-3 TR 3.6.1.2.1 Primary Containment Air Lock Seal Air Flask Pressure instrumentation TR 3.6-4 TR 3.6.1.3 Primary Containment Isolation Valves (PCIVs)

TR 3.6-5 TR 3.6.1.4 (Not Used)

TR 3.6.1.5 Primary Containment Air Temperature TR 3.6-12 TR 3.6.1.6 (Not Used)

TR 3.6.1.7 (Not Used)

TR 3.6.1.8 Penetration Valve Leakage Control System (PVLCS)

TR 3.6-13 TR 3.6.1.9 Main Steam - Positive Leakage Control System (MS-PLCS)

TR 3.6-15 TR 3.6.1.10 (Not Used)

TR 3.6.2.1 Suppression Pool Average Temperature TR 3.6-16 TR 3.6.2.2 Suppression Pool Water Level TR 3.6-17 TR 3.6.2.3 (Not Used)

TR 3.6.3.1 Primary Containment Hydrogen Recombiners TR 3.6-18 TR 3.6.3.2 (Not Used)

TR 3.6.3.3 (Not Used)

TR 3.6.4.1 (Not Used)

TR 3.6.4.2 Secondary Containment Isolation Dampers (SCIDs) and Fuel Building TR 3.6-19 Isolation Dampers (FBIDs)

TR 3.6.4.3 Standby Gas Treatment (SGT) System TR 3.6-20 TR 3.6.4.4 Shield Building Annulus Mixing System TR 3.6-21 TR 3.6.4.5 (Not Used)

TR 3.6.4.6 (Not Used)

TR 3.6.4.7 Fuel Building Ventilation System - Fuel Handling TR 3.6-23 TR 3.6.5.1 Drywell TR 3.6-24 TR 3.6.5.2 (Not Used)

TR 3.6.5.3 Drywell Isolation Valves TR 3.6-25 TR 3.6.5.4 (Not Used)

TR 3.6.5.5 Drywell Air Temperature TR 3.6-27 TR 3.7 PLANT SYSTEMS TR 3.7.1 Standby Service Water (SSW) System and Ultimate Heat Sink (UHS)

TR 3.7-1 TR 3.7.2 Control Room Fresh Air (CRFA) System TR 3.7-5 TR 3.7.3 Control Room Air Conditioning (AC) System TR 3.7-6 TR 3.7.4 (Not Used)

TR 3.7.5 Main Turbine Bypass System TR 3.7-7 TR 3.7.6 (Not Used)

TR 3.7.7 Snubbers TR 3.7-8 TR 3.7.8 Sealed Source Contamination TR 3.7-9 TR 3.7.9.1 Fire Suppression Systems TR 3.7-11 TR 3.7.9.2 Spray and/or Sprinkler Systems TR 3.7-15 TR 3.7.9.3 Halon Systems TR 3.7-18 TR 3.7.9.4 Fire Hose Stations TR 3.7-20 TR 3.7.9.5 Yard Fire Hydrants and Hydrant Hose Houses TR 3.7-24 TR 3.7.9.6 Fire-Rated Assemblies TR 3.7-27 TR 3.7.10 Area Temperature Monitoring TR 3.7-29 TR 3.7.11 Structural Settlement TR 3.7-32 RIVER BEND TR-iii Revision 62

Secondary Containment and Fuel Building Isolation Instrumentation TR 3.3.6.2 TR 3.3.6.2 Secondary Containment and Fuel Building Isolation Instrumentation TLCO DELETED RIVER BEND TR 3.3-40 Revision 62 (60i)

Secondary Containment and Fuel Building Isolation Instrumentation TR 3.3.6.2 SURVEILLANCE REQUIREMENTS DELETED RIVER BEND TR 3.3-41 oV-LUIi n

t (60ii)

Secondary Containment and Fuel Building Isolation Instrumentation TR 3.3.6.2 Table 3.3.6.2-1 Secondary Containment and Fuel Building Isolation Instrumentation FUNCTION APPLICABLE REQUIRED SURVEILLANCE NOMINAL SETPOINT MODES AND CHANNELS REQUIREMENTS OTHER PER TRIP SPECIFIED SYSTEM CONDITIONS

1.

Reactor Vessel Water Level -

Low Low, Level 2

2.

Drywell Pressure-High

3.

Fuel Building Ventilation Exhaust Radiation High (lRMS*RE5A)

4.

Fuel Building Ventilation Exhaust Radiation-High (IRMS*RE5B)

5.

Manual Initiation 1,2,3 1,2,3 (a)

(a) 2 2

1,2,3, (a)

SR SR SR SR SR SR SR SR SR SR SR SR SR SR SR SR SR SR 3.3.6.2.1 3.3.6.2.2 3.3.6.2.3 3.3.6.2.4 3.3.6.2.5 3.3.6.2.1 3.3.6.2.2 3.3.6.2.3 3.3.6.2.4 3.3.6.2.5 3.3.6.2.1 3.3.6.2.2 3.3.6.2.4 3.3.6.2.5 3.3.6.2.1 3.3.6.2.2 3.3.6.2.4 3.3.6.2.5 SR 3.3.6.2.5

-43 inches 1.68 psid 1.64 x 103 ACi/sec 5.29 x 10-4 gCi/cc NA I

(a)

During movement of recently irradiated fuel assemblies in the fuel building for fuel building isolation.

RIVER BEND TR 3.3-42 (61i)

Revision 62

Secondary Containment and Fuel Building Isolation Instrumentation TR 3.3.6.2 TABLE 3.3.6.2-2 Secondary Containment and Fuel Building Isolation Instrumentation VALVE GROUP OPERATED BY QTPUAI

TrLIAI TRIP FUNCTION

1.

Reactor Vessel Water Level-Low Low Level 2

2.

Drywell Pressure -

High

3.

Fuel Building Ventilation Exhaust Radiation - High

4.

Fuel Building Ventilation Exhaust Radiation -

High

5.

Manual Initiaion 11, 12, 13(a)(b)(c) 11, 12, 13 (a)(b)(c) 11, 12, 13 (a)(b)(c)

The valve groups listed are designated in Table 3.6.4.2-1.

(a) Also actuates ventilation isolation dampers.

(b) Also starts Standby Gas Treatment and Annulus Mixing Systems.

(c) Also starts Fuel Building Exhaust Filter Trains A and B RIVER BEND TR 3.3-43 (61ii)

Revision 62

SCIDs/FBIDs TR 3.6.4.2 TR 3.6.4.2 Secondary Containment Isolation Dampers (SCIDs) and Fuel Building Isolation Dampers (FBIDs)

TABLE 3.6.4.2-1 (page 1 of 1)

SECONDARY CONTAINMENT AND FUEL BUILDING AUTOMATIC ISOLATION DAMPERS MAXIMUM APPLICABLE ISOLATION TIME DAMPER OPERATIONAL DAMPER FUNCTION (Secondq)

GRDOIP #

CONfDITTO

1.

Shield Building Annulus Ventilation Exhaust Damper (1HVR*AOD161) 15 12 1, 2, 3

2.

Shield Building Annulus Ventilation Exhaust Damper (1HVR*AOD23A) 15 12 1, 2, 3

3.

Shield Building Annulus Ventilation Exhaust Damper (1HVR*AOD23B) 15 12 1, 2, 3

4.

Auxiliary Building Ventilation Exhaust Damper (1HVR*A00214) 15 11 1, 2, 3

5.

Auxiliary Building Ventilation Exhaust Damper (1HVR*AOD262) 15 11 1, 2, 3

6.

Auxiliary Building Ventilation Exhaust Damper (IHVR*AOD249) 15 11 1, 2, 3

7.

Auxiliary Building Ventilation Exhaust Damper (IHVR*AOO1OA) 15 11 1, 2, 3

8.

Auxiliary Building Ventilation Exhaust Damper (1HVR*AOD1OB) 15 11 1, 2, 3

9.

Auxiliary Building Ventilation Supply Damper (1HVR*AOD143) 15 11 1, 2, 3

10.

Auxiliary Building Ventilation Supply Damper (1HVR*AOD164) 15 11 1, 2, 3

11.

Fuel Building Ventilation Supply Damper (1HVF*AOD122) 15 13

12.

Fuel Building Ventilation Supply Damper (1HVF*AO0101) 15 13

13.

Fuel Building Ventilation Exhaust Damper (IHVF*AOD104) 15 13

14.

Fuel Building Ventilation Exhaust Damper (1HVF*AOD137) 15 13

15.

Fuel Building Ventilation Exhaust Damper (IHVF*AOD102) 15 13

16.

Fuel Building Ventilation Exhaust Damper (1HVF*AOD112) 15 13

Damper groups are designated in Table 3.3.6.2-2

1. When handling recently irradiated fuel in the Fuel Building.

Revision 62 RIVER BEND TR 3.6-19 (50i)

SGT TR 3.6.4.3 TR 3.6.4.3 Standby Gas Treatment (SGT)

System SURVEILLANCE REQUIREMENTS

NOTE The following surveillance requirements apply to Technical Specification LCO 3.6.4.3.

Failure to meet these surveillance requirements requires entry into Technical Specification LCO 3.6.4.3.

SURVEILLANCE TSR 3.6.4.3.1 TSR 3.6.4.3.2 TSR 3.6.4.3.3 TSR 3.6.4.3.4 TSR 3.6.4.3.5 (Not Used)

(Not Used)

Verify each SGT subsystem filter train starts and dampers align on a manual initiation signal.

FREQUENCY 4-18 months I_______________________________

RIVER BEND TR 3.6-20 (52i)

Revision 63

Diesel Fuel Oil, Lube Oil and Starting Air TR 3.8.3 TR 3.8.3 Diesel Fuel Oil, Lube Oil and Starting Air

-NOTE-------------------------------

The following surveillance requirements apply to Technical Specification LCO 3.8.3.

Failure to meet these surveillance requirements requires entry into Technical Specification LCO 3.8.3.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TSR 3.8.3.1 through TSR 3.8.3.6 (Not Used)

TSR 3.8.3.7 Verify for Diesel 1A and lB that the lube oil 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months circulating pump is operating and the lube oil sump heater and jacket water heater are OPERABLE.

TSR 3.8.3.8 Deleted RIVER BEND Revision 64 TR 3.8-6 (23i)

ADMINISTRATION TR 5.0 TR 5.4 Procedures TR 5.4.1 Written procedures shall be established, implemented, and maintained covering the activities referenced below:

a.

The applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978.

b.

The emergency operating procedures required to implement the requirements of NUREG-0737 and supplements thereto.

c.

Refueling operations.

d.

Surveillance and test activities of safety-related equipment.

e.

Security Plan implementation.

f.

Emergency Plan implementation.

g.

Fire Protection Program implementation.

h.

Process Control Program implementation.

i.

Offsite Dose Calculation Manual implementation.

j.

Quality Assurance Program for effluent and environmental monitoring.

k.

Technical Requirements Manual implementation.

1.

Technical Specifications Bases Control Program implementation.

TR 5.4.2 Each procedure of Requirement 5.4.1, and changes thereto, shall be reviewed and approved in accordance with Requirement 5.8.2.1.

TR 5.4.3 Temporary changes to procedures of Requirement 5.4.1 may be made provided:

a.

The intent of the original procedure is not altered;

b.

The change is approved by two members of the plant management

staff, at least one of whom holds a Senior Operator license on the unit affected; and

c.

The change is documented, reviewed by the FRC as required by USAR Section 13.4.1, and approved in accordance with Requirement 5.8.2.1 within 14 days of implementation.

TR 5.4.4 Procedures may use either the plant specific title listed in Technical Requirement 5.2.1 or the generic Technical Specification title when identifying a person fulfilling the responsibilities of a position delineated in Technical Specifications.

Revision 64 RIVER BEND TR 5-6

Primary Containment and Drywell Isolation Instrumentation TR 3.3.6.1 Table 3.3.6.1-1 (page 2 of 5)

Primary Containment and Dryweal Isolation Instrumentation FUNCTION APPLICABLE REQUIRED CONDITIONS SURVEILLAJNCE NOMINAL MODES OR CHANNELS REFERENCED REQUIREMENTS SETPOINT OTHER PER TRIP FROM SPECIFIED SYSTEM REQUIRED CONDITIONS ACTION C.1 I. Main Steam Line Isolation (continued)

h.

Main Steam Line Turbine Shield Wall Temperature-High

i.

MSL Moisture Separator and Reheater Area Temperature -High

1. Manual Initiation

k.

DELETED

1. Main Steam Line Radiation -

High-High

2.

Primary Containment and Drywell Isolation

a.

Reactor Vessel Water Level - Low Low, Level 2

b.

Drywell Pressure-High

c.

Containment Purge Isolation Radiation High

d.

Manual Initiation 1,2,3 1,2,3 1,2,3 1,2,3 1,2,3 1,2,3 1,2,3 1,2,3 2

2 1 (f) 2 (b) 2 (b) 1 (continued)

(b)

Also required to initiate the associated drywell isolation function.

(f)

Only trips and isolates mechanical vacuum pumps, reactor sample valves, and provides monritoring/alarm (h)

Setpoints to be verified:

1) Within 30 days after a significant change in hydrogen injection, or

2)

During Mode 1 or 2 with a mechanical vacuum pump in operation.

D SR SR SR SR SR D

SR SR SR SR SR SR 3.3.6.1.6 3.3.6.1.1 3.3.6.1.2 3.3.6.1.3 3.3.6.1.5 3.3.6.1.6 3.3.6.1.1 3.3.6.1.2 3.3.6.1.3 3.3.6.1.5 3.3.6.1.6 TLCO L TSR TSR TSR TSR H

SR SR SR SR SR H

SR SR SR SR SR K

SR SR SR SR G

SR 3.3.6.1.6 3.3.6.1.1 3.3.6.1.2 3.3.6.1.5 3.3.6.1.6 3.3.6.1.1 3.3.6.1.2 3.3.6.1.3 3.3.6.1.5 3.3.6.1.6 3.3.6.1.1 3.3.6.1.2 3.3.6.1.3 3.3.6.1.5 3.3.6.1.6 3.3.6.1.1 3.3.6.1.2 3.3.6.1.5 3.3.6.1.6 108*F 126'F NA 3.Ox full power background (Allowable Value 5 3.6 x

full power background)

(h)

-43 inches 1.68 psid 1.17 R/hr RIVER BEND TR 3.3-33 (57ii)

Revision 65 I

2 (b)

NA

AC Sources-Operating TR 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY TSR 3.8.1.12

( Not Used (continued)

RIVER BEND Revision 65 TR 3.8-2 (15ii)

AC Sources-Shutdown TR 3.8.2 SURVEILLANCE REQUIREMENTS NOTE.............

The following surveillance requirements apply to Technical Specification LCO 3.8.2.

Failure to meet these surveillance requirements requires entry into Technical Specification LCO 3.8.2.

SURVEILLANCE FREQUENCY TSR 3.8.2.1 NOTE-------------------

The following TSRs are not required to be performed:

TSR 3.8.1.18, and TSR 3.8.1.21.

For AC sources required to be OPERABLE, the following TSRs are applicable:

In accordance with applicable TSR 3.8.1.2 TSR 3.8.1.18, TSRs TSR 3.8.1.20 TSR 3.8.1.21 RIVER BEND TR 3.8-5 (20i)

Revision 65

ADMINISTRATION TR 5.0 TR 5.3 Unit Staff Qualifications TR 5.3.1 Licensed Operator Qualifications The licensed Operators and Senior Operators shall also meet or exceed the minimum qualifications of ANSI/ANS 3.1-1978.

TR 5.3.2 Licensed Operator Training A retraining and replacement training program for the unit staff shall be maintained under the direction of the Manager-Training and Development and shall meet the requirements of 10 CFR Part 55 and shall include familiarization with relevant industry operational experience.

TR 5.3.3 Unit Staff Training Other than for Licensed Operators, a retraining and replacement training program for unit staff shall be maintained under the direction of the Manager-Training and Development and shall meet or exceed the recommendations of ANSI/ANS 3.1-1978 and shall include familiarization with relevant industry operational experience.

Revision 65 RIVER BEND TR 5-5

TR I.I 1.1 Definitions (continued)

MODE OFFSITE DOSE CALCULATION MANUAL (ODCM)

OPERABLE/ OPERABILITY Operations With a Potential for Draining the Reactor Vessel (OPDRVs)

RATED THERMAL POWER (RTP)

A MODE shall correspond to any one inclusive combination of mode switch position, average reactor coolant temperature, and reactor vessel head closure bolt tensioning specified in Table 1.1-1 with fuel in the reactor vessel.

The OFFSITE DOSE CALCULATION MANUAL shall contain the methodology and parameters used in the calculation of offsite doses due to radioactive gaseous and liquid effluents and in the calculation of gaseous and liquid effluent monitoring alarm/trip setpoints.

It shall also contain a table and figure defining current radiological environmental monitoring sample locations.

A system, subsystem, division, component, or device shall be OPERABLE or have OPERABILITY when it is capable of performing its specified safety function(s) and when all necessary attendant instrumentation, controls, normal or emergency electrical power, cooling and seal water, lubrication, and other auxiliary equipment that are required for the system, subsystem, division, component, or device to perform its specified safety function(s) are also capable of performing their related support function(s).

An OPDRV consists of those operations or maintenance that:

a.

have the potential to uncover irradiated fuel in the reactor pressure vessel or for Operations With the Potential to Drain the Reactor Cavity (OPDRCs),

containment fuel storage pool, and

b.

involve vessel penetrations or piping greater than 1-1/4 inches which penetrate the RPV below the LPCI nozzles (not to include the LPCI nozzles).

Work on multiple lines with a total equivalent diameter exceeding 1-1/4 inches are included, and

c.

an acceptable barrier or otherwise addressed measures are not in place to provide reasonable assurance that an error in the maintenance or operations activity will not cause drainage of the reactor pressure vessel.

RTP shall be a total reactor core heat transfer rate to the reactor coolant of 3039 MWt.

(continued)

Revision 66 I

RIVER BEND TR 1-8

Main Turbine Pressure Regulation System TR 3.2.5 TR 3.2 POWER DISTRIBUTION LIMITS TR 3.2.5 Main Turbine Pressure Regulation System TLCO 3.2.5 APPLICABILITY:

Both Main Turbine Steam Pressure Regulators shall be OPERABLE.

THERMAL POWER Ž 23.8% RTP.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One main turbine steam A.1 Verify THERMAL POWER is 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months pressure regulator

> 90% RTP.

inoperable.

OR A.2 Establish the applicable 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months thermal limits per the COLR.

B.

Required Actions and B.1 Reduce THERMAL POWER to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months associated Completion

< 23.8% RTP.

Times not met.

TECHNICAL SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.2.5.1 Verify both main steam turbine pressure Once within 12 regulators are OPERABLE.

hours after

Ž 23.8% RTP AND 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter RIVER BEND TR 3.2-1 (6i)

Revision 66 I

I

RPS

-7sruene'T-a:3..!

TIR 3.3.1-1 Tanle 3.3.'.-

page I of 3r Reaczcr Protec:zin Sysrem instrumentanion FUNCTION APPLICABLE REQUIRED CONDITIONS SURVEILLANCE NOMINAL SETPOINT/

MODES OR CEINNELS REFERENCED REQUIREMENTS RESPONSE TIME OTHER PER 7R7?

FROM SPECIFIED SYSTEM REQUIRED COND:TIONS ACTION D.1 Average Power Pan;e Mcni:0rs

continuedI c

FeideI Neutron Fl.x H gh SR SR SR SR SR SR C.

noo 3.3.1.I.

3.3.1.1.2 3.3.1.1.8 3.3.1.1.9 3.3.1.1.11 3.3.1.15 3.3.1.1.18 SR 3.3.1.1.8 SR 3.3.1.9 SR 3.3.1.15 Reactor Vessei Steam Dome Pressure - High SR SR SR SR SR SR SR SR SR SR SR SR Reactor Vessel Water Level L~w, L.evei 3 3eacr7-Vessel Water Level-

>- 23.8% RTP Le'.'-e!

9 6

a. i3:n Steam Isolation Valve ae)

F SR SR SR SR SR SR SR SR SR SR H

SR SR SR SR SR 1,2 3.3.1.1.1 3.3.1.1.9 3.3.1.1.10 3.3.1. 1. 13 3.3.1.1.15 3.3.1.1.18 3.3.1.1.1 3.3.1.1.9 3.3.1.1.10 3.3.11.1.13 3.3.1.1.15 3.3.1.1.18 3.3.1.1.1 3.3.1.1.9 3.3.1.1.10 3.3.1.1.13 3.3.1.1.15 3.3.1.1.18 3.3.1.1.9 3.3.1.1.13 3.3. 1. 1. 15 3.3.1.1.18 3.3.1.1.1 3.3.1.1.9 3.3. 1. 1. 10 3.3. 1.1. 13 3.3.1.1.15 119%

RTP 5d)

<- 0.09 se NA iC64.7 osiq

< 3.35 sec Sinches TL < 1.-5 s3C 1L <

.05 sec

ýh)

.1-9% closed 5 0.09 sec 1.

6 8 psid (con-- rn-eo,

,b!,

,c),

(f),

(g) not used this page Response time shall be measured from the detector output or from the input to the first electronic the channel.

This function automatically bypassed with the reactor mode switch not in RUN.

7L - 7x - Tc; where:

7- = Measured total response time of the isolation system instrumentation

= Hydraulic response time of the channel sensor measured upon initial installation Tc = Measured response time of the logic circuit excluding the channel sensor 7he given numerical value is the acceptance criterion For TL.

In case 'he sensor is replaced or refurbished, a hydraulic response time test must be performed to determine revised value for T,.

RIVER BEND TR3.3-3 (9ii)

Revision 66 (continuec*

Recirculation Loops Operating (Single Loop]

TR 3.4.1.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TSR 3.4.1.1.1 Verify volumetric loop flow rate of the loop in Initially, within operation is

! 33000 gpm.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter TSR 3.4.1.1.2 Verify THERMAL POWER is

79% RTP.

Initially, within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter TSR 3.4.1.1.3 Verify flow control is in Loop Manual.

Initially, within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter RIVER BEND TR 3.4-3 (5ii)

Revision 66

RCS Pressure and Temperature (P

T)

Limi7 s Vessel ?ycro TR 3.4.11.1 TR 3.4.11.1 RCS Pressure and Temperature (P/T) Limits(Vessel Hdyro)

TLCO 3.4.11.1 Applicability RPV heatup/cooldown limit shall be

10'F in any one hour period During RCS inservice leak and hydrostatic testing while above the non-nuclear heating limit ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A

Technical Soecification A.1 Limit the heatup and Immediately Figure 3.4.11-1 curves A cooldown rate to :

10OF in and A' exceeded during any one hour period.

RCS inservice leak and hydrostatic testing.

RIVER BEND TR 3.4-11 (32ii)

Revision 66

TR 3.3.7.1 TR 3.3.7.2 TR 3.3.7.3 TR 3.3.7.4 TR 3.3.7.5 TR 3.3.7.6 TR 3.3.7.7 TR 3.3.7.8.1 TR 3.3.7.8.2 TR 3.3.7.8.3 TR 3.3.8.1 TR 3.3.8.2 TR 3.3.9 TR 3.3.10 TR 3.3.11.2 TR 3.3.11.3 TR 3.3.12 TECHNICAL REQUIREMENTS MANUAL TABLE OF CONTENTS Control Room Fresh Air (CRFA) System Turbine Overspeed Protection (Deleted)

Feedwater/Main Turbine Level 8 Trip Instrumentation Fire Detection Instrumentation Seismic Monitoring Instrumentation Loose-Part Detection System (Deleted)

Traversing In-core Probe System (Not Used)

Offgas System Radiation Monitoring Instrumentation Offgas System Hydrogen Monitoring Instrumentation Loss of Power (LOP) Instrumentation RPS Electric Power Monitoring (Not Used)

(Not Used)

Radioactive Liquid Effluent Monitoring Radioactive Gaseous Effluent Monitoring Meteorological Monitoring Instrumentation TR 3.4 REACTOR COOLANT SYSTEM (RCS)

TR 3.4.1 Recirculation Loops Operating TR 3.4.1.1 Recirculation Loop Operating (Single Loop)

TR 3.4.2 (Not Used)

TR 3.4.3 (Not Used)

TR 3.4.4 Stuck Open Safety/Relief Valves (S/RVs)

TR 3.4.5 RCS Operational LEAKAGE TR 3.4.6 Reactor Coolant System Pressure Isolation Valves TR 3.4.6.1 Reactor Coolant System Pressure Isolation Valve Pressure Monitors TR 3.4.7 RCS Leakage Detection Instrumentation TR 3.4.8 (Not Used)

TR 3.4.9 (Not Used)

TR 3.4.10 (Not Used)

TR 3.4.11 RCS Pressure and Temperature (P/T) Limits TR 3.4.11.1 Pressure/Temperature Limits (Vessel Hdyro)

TR 3.4.11.2 Second Recirculation Loop Startup TR 3.4.12 (Not Used)

TR 3.4.13 Chemistry TR 3.4.14 Structural Integrity TR 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM TR 3.5.1 ECCS - Operating TR 3.5.1.1 ECCS-Operating (keep fill)

TR 3.5.2 (Not Used)

TR 3.5.3 (Not Used)

TR 3.5.4 Suppression Pool Pumpback System (SPPS)

RIVER BEND TR-ii TR 3.3-48 TR 3.3-51 TR 3.3-53 TR 3.3-55 TR 3.3-62 TR 3.3-65 TR 3.3-66 TR 3.3-69 TR 3.3-72 TR 3.3-74 TR 3.3-75 TR 3.3-76 TR 3.3-81 TR 3.3-86 TR 3.4-1 TR 3.4-2 TR 3.4-4 TR 3.4-5 TR 3.4-6 TR 3.4-7 TR 3.4-9 TR 3.4-10 TR 3.4-11 TR 3.4-12 TR 3.4-13 TR 3.4-17 TR 3.5-1 TR 3.5-2 TR 3.5-3 Revision 67

Loose-part Detection System TR 3.3.7.6 TR 3.3.7.6 Loose-part Detection System I SPECIFICATION DELETED RIVER BEND TR 3.3-65 (71xviii)

Revision 67

AC Sources-Operating TR 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY TSR 3.8.1.13 -

TSR 3.8.1.17 (Not Used)

TSR 3.8.1.18 18 months a.,

b.

(Not Used)

c.

When the DG is auto-started from standby condition for technical specification SR 3.8.1.18

1. -

4.

(Not Used)

5.

Verify the auto-connected loads for each diesel do not exceed 3130 KW for diesel generator 1A and lB and 2600 KW for diesel generator 1C.

TSR 3.8.1.19 (Not Used)

TSR 3.8.1.20 NOTE --------------

Once per 24 Not required to be met when Division III hours diesel engine is running.

OR Verify the Division III diesel generator ambient room temperature to be Ž 40'F Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months when the last reported room temperature

< 50OF.

TSR 3.8.1.21 (Deleted)

RIVER BEND TR 3.8-3 (15iii)

Revision 67

AC Sources-Shutdown TR 3.8.2 SURVEILLANCE REQUIREMENTS

NOTE ---------------

The following surveillance requirements apply to Technical Specification LCO 3.8.2.

Failure to meet these surveillance requirements requires entry into Technical Specification LCO 3.8.2.

SURVEILLANCE TSR 3.8.2.1 NOTE The following TSR is not required to be performed:

TSR 3.8.1.18.

For AC sources required to be OPERABLE, the following TSRs are applicable:

TSR 3.8.1.2 TSR 3.8.1.18, TSR 3.8.1.20 FREQUENCY i _______________________________________________

In accordance with applicable TSRs RIVER BEND TR3.8-5 (20i)

Revision 67

PCI Vs TR 3.6.1.3 TABLE 3.6.1.3-1 (page 1 of 6)

PRIMARY CONTAINMENT ISOLATION VALVES MAXIMUM SECONDARY ISOLATION CONTAINMENT PENETRATION VALVE TIME SYSTEM VALVE NUMBER(a)

NUMBER flRU2(L)

(Seconds)

BYPASS PATH (Yes/No)

a.

Automatic Isolation Valves MSIV 1B21*AOVFO22A(b)(g) 1KJB*Z1A 6

5 No MSIV 1B21.AOVFO22B(b)(g) 1KJB*Z1B 6

5 No MSIV 1B21.AOVFO22c(b)(g) 1KJB*Z1C 6

5 No MSIV 1B21.AOVFO22D(b)(g) 1KJB*ZlD 6

5 No MSIV 1B21*AOVFO28A(g) 1KJB*ZlA 6

5 No MSIV 1B21*AOVFO28B(g) 1KJB*Z1B 6

5 No MSIV 1B21*AOVFO28C(g) 1KJB*Z1C 6

5 No MSIV B21*,AOVFO28D(g) 1KJB*Z1D 6

5 No Turbine Plant Misc. Drains 1B21*MOVFO67A(g) 1KJB*ZIA 6

19.8 No Turbine Plant Misc. Drains 1821*MOVFO67B(g) 1KJB*ZIB 6

19.8 No Turbine Plant Misc. Drains 1B21,MOVFO67C(g) 1KJB*ZIC 6

19.8 No Turbine Plant Misc. Drains 1B21,MOVFO671(g) 1KJB*ZID 6

19.8 No Turbine Plant Misc. Drains 1B21,MOVFO16(b)(g) 1KJB*Z2 6

16.5 No Turbine Plant Misc. Drains B21,*MOVFO19(g) 1KJB*Z2 6

17.6 No RHR Return to FW 1E12*MOVFO53A(m) 1KJB*Z3A 5

39 No RHR Return to FW 1E12*MOVFO53B(m) 1KJB*Z3B 5

39 No 1DRB*Z13 RHR Shutdown Cooling Supply 1E12*MOVFO08 1IKJB*Z20 5

29.7 No RHR Shutdown Cooling Supply 1E12*MOVFOO9(b) 1KJB*Z20 5

25.3 No LPCI A to Reactor 1E12*MOVFO37A(m) 1KJB*Z21A 14 73.7 No LPCI B to Reactor 1E12*MOVFO37B(m) 1KJB*Z21B 14 74.8 No MS-PLCS Line 1E33*MOVFOOB(d)(k) 1KJB*Z1A,B,C, 4

14.5 No D

RWCU Disch. to Condenser 1G33*MOVF028 1KJB*Z4 15 20.9 Yes RWCU Return to FW 1G33*MOVF04O 1IKJB*Z6 15 24.2 No RWCU Pump Suction 1G33*MOVFOO1(b) 1KJB*Z7 16 19.8 No RWCU Pump Disch.

1G33*MOVF053 1KJB*Z129 15 6.5 No RWCU Disch. to Condenser 1G33*MOVF034 1KJB*Z4 15 20.9 Yes RWCU Return to FW 1G33*MOVF039 1KJB*Z6 15 24.2 No RWCU Pump Suction 1G33*MOVFO04 1KJB*Z7 7

19.8 No RWCU Pump Disch.

1G33*MOVF054 1KJB*Z129 15 6.5 No RWCU Backwash Disch.

1WCS*MOV178 1KJB*Z5 1

12.1 Yes RWCU Backwash Disch.

1WCS*MOV172 1KJB*Z5 1

12.6 Yes HPCS Test Return-Supp. Pool

¶E22*MOVFO23(J) 1KJB*Z11 1

50 No continued RIVER BEND TR 3.6-6 (20ii)

Revision 68

PCIVs TR 3.6.1.3 TABLE 3.6.1.3-1 PRIMARY CONTAINMENT ISOLATION VALVES (page 3 of 6)

MAXIMUM SECONDARY ISOLATION CONTAINMENT PENETRATION VALVE TIME SYSTEM VALVE NUM&ER(a)

NUMBER GfROUP( L)

(Seconds)

BYPASS PATH (Yes/No)

b.

Manual Isolation Valves LPCI A to Reactor LPCI B to Reactor Reactor Plant Vent.

DP Trans.

Reactor Plant Vent.

DP Trans.

PVLCS Pressure Transmitter Reactor Plant Vent. DP Trans.

Cont.

Leakage Monitor Press.

Cont.

Leakage Monitor Press.

Cont.

Leakage Monitor Press.

Cont.

Leakage Monitor Press.

Cont. Monitor Press. Sensing Cont. Monitor Press. Sensing Reactor Plant Vent.

DP Trans.

Reactor Plant Vent.

DP Trans.

Cont. Monitor Press. Sensing Cont. Monitor Press. Sensing PVLCS Pressure Transmitter Reactor PLant Vent.

DP Trans.

LPCI A to Reactor LPCI B to Reactor SW Rtn Vacuum Release SW Rtn Vacuum Release SW Rtn Vacuum Release SW Rtn Vacuum Release Feedwater Line Feedwater Line HPCS Pump Suction from Supp.

Pool HPCS to Reactor HPCS Min. Flow Bypass Supp. Pool Pumpback Rtn.

LPCS Suction from Supp. Pool LPCS to Reactor RCIC Turbine Exh. to Supp. Pool RCIC Min. Flow Bypass RHR/RCIC Injection LPCI A to Reactor LPCI A to Reactor LPCI B to Reactor LPCI B to Reactor LPCI C to Reactor RHR/RCIC Injection 1E12*FO99A 1E12*FO99B 1HVR*V8(k) 1HVR*V1O(k) 1LSV*V64(k) 1HVR*V12(k) 1LMS*V14 1LMS*V12 1LMS*V7 1LMS*V16 1CMS*V2(k) 1CMS*V3(k) 1HVR*V14(k) 1HVR*V16(k) 1CMS*V16(k) 1CMS*V15(k) 1LSV*V65(k) 1HVR*V18(k) 1E12*VFO44A 1E12*VFO44B 1SWP*SOV522A(e) 1SWP*SOV522B(e) 1SWP*SOV522C(e) 1SWP*SOV522D(e) 1FWS*MOV7A(e) 1FWS*MOV7B(e) 1E22*MOVFO15(e)(j) 1E22*MOVFO04(b)(e) 1E22*MOVFO12(e)(J) 1DFR*MOV146(e)(j) 1E21*MOVFOO1(e)(J) 1E21*MOVFOO5(b)(e) 1E51*MOVFO68(e)(j)(q) 1E51*MOVFO19(e)(j)(p) 1E51*MOVF013(e) 1E12*MOVFO27A(e) 1E12*MOVFO42A(e) 1E12*MOVFO27B(e) 1E12*MOVFO42B(e) 1E12*MOVFO42C(e) 1E12*MOVF023 RIVER BEND TR3.6-8 (20iv)

Revision 68 1KJB*Z21A 1KJB*Z21B 1KJB*Z602A 1KJB*Z602B 1KJB*Z602D 1KJB*Z602F 1KJB*Z603A 1KJB*Z603A 1KJB*Z603C 1KJB*Z603C 1KJB*Z605A 1KJB*Z605B IKJB*Z606A 1KJB*Z606B 1IKJB*Z606C 1KJB*Z606D 1KJB*Z606E 1KJB*Z606F 1KJB*Z21A 1KJB*Z21B 1KJB*Z53A 1KJB*Z53B 1KJB*Z53A 1KJB*Z53B 1IKJB*Z3A 1KJB*Z3B 1IKJB*Z8 1KJB*Z9, 1DRB*Z10 1KJB*Z11 1KJB*Z11 1KJB*Z12 1KJB*Z13, 1DRB*Z14 1KJB*Z17 1KJB*Z18A 1KJB*Z3A 1KJB*Z21A 1KJB*Z21A 1KJB*Z21B 1KJB*Z21B 1KJB*Z21C 1KJB*Z3A No No No No No No No No No No No No No No No No No No No No No No No No Yes Yes No No No No No No No No No No No No No No No continued

PCIVs TR 3.6.1.3 TABLE 3.6.1.3-1 (page 4 of 6)

PRIMARY CONTAINMENT ISOLATION VALVES MAXIMUM SECONDARY ISOLATION CONTAINMENT PENETRATION VALVE TIME SYSTEM VALVE NUMBER(a)

UMBER GROUP BYPASS PATH (1)

(Yes/No)

b.

ManuaL Iolation Vatvep continued RHR A Hx V&R to Supp. Pool RHR B Hx V&R to Supp. Pool RHR A Min. Flow Bypass LPCS Min. Flow Bypass Post-Acc. Sample Return RHR B Min.

Flow Bypass RHR C Min.

Flow Bypass RHR A Suction-Supp. Pool RHR B Suction-Supp. Pool RHR C Suction-Supp. Pool CRD Hydraulic Sys. Sup.

Cont.

Hydrogen Purge Outlet Cont.

Hydrogen Purge Outlet SW Supply SW SuppLy SW Return SW Return SW Return SW Return Air Sup. for Main Steam SRV Air Sup. for Main Steam SRV Cont. Hydrogen Purge Sup.

Hydrogen Sample Sup.

Hydrogen Sample Rtn.

Hydrogen Sample Sup.

Hydrogen Sample Rtn.

1E12*MOVFO73A(e)(j)(q) 1E12*MOVFO73B(e)(j)(q) 1E12*MOVFO64A(e)(j)(P) 1E21*MOVFO11(e)(j)(p) 1SSR*SOV139(e)(j) 1E12*MOVFO64B(e)(j)(p) 1E12*MOVFO64C(e)(j)(p) 1E12*MOVFOO4A(e)(j) 1E12*MOVFOO4B(e)(j) 1E12*MOVF105(e)(j) 1C11*MOVF083(e) 1CPP*MOV104(e)

ICPP*MOV105(e)

ISWP*MOV5O7A(e) 1SWP*MOV507B(e) 1SWP*MOV81A(e) 1SWP*MOV81B(e) 1SWP*MOV503A(e) 1SWP*MOV5O3B(e) 1SVV*MOVIB(e) 1SVV*MOVIA(e) 1CPP*SOV140(e) 1CMS*SOV35D(e)(r) 1CMS*SOV31B(e)(r) 1CMS*SOV35B(e)(r) 1CMS*SOV31D(e)(r) 1CMS*SOV35C(e)(r) 1CMS*SOV31A(e)(r) 1CMS*SOV35A(e)(r) 1CMS*SOV31C(e)(r)

RIVER BEND TR 3.6-9 (20v)

Revision 68 1KJB*Z23A 1KJB*Z23B 1KJB*Z24A 1KJB*Z24A 1KJB*Z23B 1KJB*Z24B 1KJB*Z24C 1KJB*Z25A 1KJB*Z25B 1KJB*Z25C 1KJB*Z29 1KJB*Z33 1KJB*Z33 1KJB*Z52A 1KJB*Z52B 1KJB*Z53A 1KJB*Z53B 1KJB*Z53A 1KJB*Z53B 1KJB*Z102 1KJB*Z103 1KJB*Z31 1KJB*Z601E 1KJB*Z6O1E 1KJB*Z601 F 1KJB*Z601 F 1KJB*Z605E 1KJB*Z605E 1KJB*Z605F 1KJB*Z605F No No No No No No No No No No No No No No No No No No No No No No No No No No No No No No continued

PCIVs TR 3.6.1.3 TABLE 3.6.1.3-1 (page 6 of 6)

PRIMARY CONTAINMENT ISOLATION VALVES MAXIMUM SECONDARY ISOLATION CONTAINMENT PENETRATION VALVE TIME SYSTEM VALVE IUMBER(a)

NUMBER GROUP_)

(Seconds)

BYPASS PATH (Yes/No)

C.

Other lgonttinn Valves continued Equip. Drain Disch.

1DER*V4 1KJB*Z38 No Floor Drain Disch.

1DFR*V180 1KJB*Z35 No Fire Protection Hdr.

1FPW*V263 1KJB*Z41 Yes Service Air Supply 1SAS*V486 1KJB*Z44 Yes Instr. Air Supply 1IAS*V80 1KJB*Z46 Yes RPCCW Supply 1CCP*V118 1KJB*Z48 No RPCCW Return 1CCP*V160 1KJB*Z49 No Service Water Supply 1SWP*V174 1KJB*Z52A No Service Water Supply 1SWP*V175 1KJB*Z52B No Air Sup. for Main Steam SRV 1SVV*V9 1KJB*Zl02 No Air Sup. for Main Steam SRV 1SVV*V31 1KJB*Zl03 No Vent. Chilled Water Rtn.

1HVN*V1316 1KJB*Z131 Yes Vent. Chilled Water Sup.

IHVN*V541 1KJB*Z132 Yes Condensate Makeup Sup.

1CNS*V86 1KJB*Z134 Yes (a)

Subject to a Type C leak rate test at a test pressure of 7.6 psig except as otherwise noted.

(b)

Also isolates the drywell.

(c)

Testable check valve.

(d)

Isolates on MS-PLCS air line high flow or MS-PLCS air line header to Main Steam Line low differential pressure.

(e)

Receives a remote manual isolation signal.

(f)

DELETED (g)

This valve sealed by the main steam positive leakage control system (MS-PLCS).

Valves sealed by the MS-PLCS are tested in accordance with Technical Specification Surveillance Requirement SR 3.6.1.3.8 to verify that leakage does not exceed the limit specified in the SR.

This leakage is not included in the 0.60 La Type B and C test total.

(h)

DELETED (j)

Valve is provided with a water seal by the Suppression Pool. Type A, C testing is not required.

(k)

Not subject to a Type A, B, or C teak rate test.

(L) Valve groups are designated in Table 3.3.6.1-2 (m)

The valve position indications for these valves are not required for Technical Specification LCO 3.3.3.1.

(n)

DELETED.

(o)

DELETED.

(p)

In Modes 4 and 5, an equilvalent isolation barrier for LCO 3.6.1.10 is established by maintaining a minimum suppression pool level of 18 feet.

(q)

In Modes 4 and 5, an equivalent isolation barrier for LCO 3.6.1.10 is established by maintaining a minimum suppression pool level of 18 feet, provided penetrations KJB-Z18B and KJB-Z18C are isolated.

(r)

This valve is open post-accident, not subject to type C test.

RIVER BEND TR 3.6-11 Revision 68 (20vii)

Primary Containment -

Operating TR 3.6.1.1 TABLE 3.6.1.1-i LEAKAGE PATHS SECONDARY CONTAINMENT BYPASS LEAKAGE PATHS TO THE FUEL BUILDING PENETRATION Containment air lock 1JRB*DRA2 ANNULUS BYPASS LEAKAGE PATHS TO THE AUXILIARY BUILDING VALVE NO.

VALVE NO.

PENETRATION (DIV.

I)

(DIV.

II)

IKJB*Z31 IHVR*AOV165 IHVR*AOV123 1KJB*601E lSSR*SOV133 lSSR*SOV134 IKJB*601F lSSR*SOV140 lSSR*V706 lKJB*601B lSSR*SOV131 lSSR*SOV130 Containment air lock IJRB*DRAl CRD removal hatch RIVER BEND TR 3.6-2 (2ii)

Revision 69 1.

2.

PC7Vs TR 3.6.1.3 TABLE 3.6.1.3-1 (page 4 of 6)

PRIMARY CONTAINMENT ISOLATION VALVES MAXIMUM SECONDARY ISOLATION CONTAINMENT PENETRATION VALVE TIME VALVE NUMRnR(a)

NUM1BFR GROUP

.LS*econs BYPASS PATH (1)

____________________(Yes/No)

b.

Manual ITsolation Valve(

/N continued RHR A Hx V&R to Supp. Pool 1E12*MOVFO73A(e)(j)(q) 1KJB*Z23A No RHR B Hx V&R to Supp.

Pool 1E12*MOVFO738(e)(j)(q) 1KJB*Z23B No RHR A Min.

Flow Bypass 1E12*MOVFO64A(e)(j)(p) 1KJB*Z24A No LPCS Min.

Flow Bypass 1E21*MOVFO11(e)(j)(p) 1KJB*Z24A No Post-Acc. Sample Return 1SSR*SOV139(e)(j) 1KJB*Z23B No RHR B Min.

Flow Bypass 1E12*MOVFO64B(e)(j)(p) 1KJB*Z24B No RHR C Min.

Flow Bypass 1E12*MOVF064C(e)(j)(p) 1KJB*Z24C No RHR A Suction-Supp. Pool 1E12*MOVFOO4A(e)(j) 1KJB*Z25A No RHR B Suction-Supp. Pool 1E12*MOVFOO4B(e)(j) 1KJB*Z25B No RHR C Suction-Supp. Pool 1E12*MOVF1O5(e)(j) 1KJB*Z25C No CRD Hydraulic Sys. Sup.

1C11*MOVFD83(e) 1KJB*Z29 No Cont. Hydrogen Purge Outlet 1CPP*MOV104(e) 1KJB*Z33 No Cont. Hydrogen Purge Outlet ICPP*MOV105(e) 1KJB*Z33 No SW Supply 1SWP*MOV507A(e) 1KJB*Z52A No SW Supply 1SWP*MOV507B(e) 1KJB*Z52B No SW Return 1SWP*MOV81A(e) 1KJB*Z53A No SW Return 1SWP*MOV81B(e) 1KJB*Z53B No SW Return 1SWP*MOV503A(e) 1KJB*Z53A No SW Return 1SWP*MOV503B(e) 1KJB*Z53B No Air Sup. for Main Steam SRV 1SVV*MOV1B(e) 1KJB*Zl02 No Air Sup. for Main Steam SRV 1SVV*MOV1A(e) 1KJB*Zl03 No Cont. Hydrogen Purge Sup.

1CPP*SOV140(e) 1KJB*Z31 No Hydrogen Sample Sup.

1CMS*SOV35D(e)(r) 1KJB*Z601E No Hydrogen Sample Sup.

1CMS*SOV31B(e)(r) 1KJB*Z601E No Hydrogen Sample Rtn.

1CMS*SOV35B(e)(r) 1KJB*Z601F No Hydrogen Sample Rtn.

1CMS*SOV31D(e)(r) 1KJB*Z601F No Hydrogen Sample Sup.

1CMS*SOV35C(e)(r) 1KJB*Z605E No Hydrogen Sample Sup.

1CMS*SOV31A(e)(r) 1KJB*Z605E No Hydrogen Sample Rtn.

1CMS*SOV35A(e)(r) 1KJB*Z605F No Hydrogen Sample Rtn.

1CMS*SOV31C(e)(r) 1KJB*Z605F No IFTS Drain Line Isol. Vlv.

1F42-MOVF003(h) 1F42*GO01 Yes continued RIVER BEND TR 3.6-9 Revision 69 (20v)

PCIVs TR 3. 6. 1. 3 TABLE 3.6.1.3-1 (page 6 of 6)

PRIMARY CONTAINMENT ISOLATION VALVES MAXIMUM SECONDARY ISOLATION CONTAINMENT PENETRATION VALVE TIME SYSTEM VALVE NUMFER(a)

NUMBER ngnL~p() L Seconds)

BYPASS PATH

c.

Other Isolation Valves (Yes/No) continued Equip. Drain Disch.

1DER*V4 1KJB*Z38 No Floor Drain Disch.

1DFR*V180 1KJB*Z35 No Fire Protection Hdr.

1FPW*V263 1KJB*Z41 Yes Service Air Supply 1SAS*V486 1KJB*Z44 Yes Instr. Air Supply 11AS*V80 1KJB*Z46 Yes RPCCW Supply 1CCP*V118 1KJB*Z48 No RPCCW Return 1CCP*V160 1KJB*Z49 No Service Water Supply 1SWP*V174 1KJB*Z52A No Service Water Supply 1SWP*V175 1KJB*Z52B No Air Sup. for Main Steam SRV 1SVV*V9 1KJB*Z102 No Air Sup. for Main Steam SRV 1SVV*V31 1KJB*ZI03 No Vent. Chilled Water Rtn.

1HVN*V1316 1KJB*Z131 Yes Vent. Chilled Water Sup.

IHVN*V541 1KJB*Z132 Yes Condensate Makeup Sup.

1CNS*V86 1KJB*Z134 Yes (a)

Subject to a Type C leak rate test at a test pressure of 7.6 psig except as otherwise noted.

(b)

Also isolates the drywell.

(c)

Testable check valve.

(d)

Isolates on MS-PLCS air Line high flow or MS-PLCS air line header to Main Steam Line low differential pressure.

(e)

Receives a remote manual isolation signal.

(f)

DELETED (g)

This valve sealed by the main steam positive Leakage control system (MS-PLCS).

Valves sealed by the MS-PLCS are tested in accordance with Technical Specification Surveillance Requirement SR 3.6.1.3.8 to verify that leakage does not exceed the limit specified in the SR.

This leakage is not included in the 0.60 La Type B and C test total.

(h)

This valve fulfills the containment isolation function in accordance with License Amendment 116 white the IFTS blind flange is removed during Modes 1, 2, and 3.

(j)

Valve is provided with a water seal by the Suppression Pool. Type A, C testing is not required.

(k)

Not subject to a Type A, B, or C leak rate test.

(l)

Valve groups are designated in Table 3.3.6.1-2 (m)

The valve position indications for these valves are not required for Technical Specification LCO 3.3.3.1.

(n)

DELETED.

(o)

DELETED.

(p)

In Modes 4 and 5, an equilvatent isolation barrier for LCO 3.6.1.10 is established by maintaining a minimum suppression pool level of 18 feet.

(q)

In Modes 4 and 5, an equivalent isolation barrier for LCO 3.6.1.10 is established by maintaining a minimum suppression pool Level of 18 feet, provided penetrations KJB-Z18B and KJB-Z18C are isolated.

Cr)

This valve is open post-accident, not subject to type C test.

RIVER BEND TR 3.6-11 Revision 69 (20vii)

Refueling Platform TR 3.9.12 TR 3.9.12 Refueling Platform TLCO 3.9.12 APPLICABILITY:

The refueling platform shall be OPERABLE and used for handling fuel assemblies or control rods.

During handling of fuel assemblies or control rods.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more requirements A.1 Suspend use of any

NOTE-------

for refueling platform inoperable refueling Place the load in OPERABILITY not platform equipment from a safe condition satisfied.

operations involving the prior to handling of control rods suspending and fuel assemblies operation.

Immediately SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TSR 3.9.12.1.

Demonstrate operation of the overload cutoff on Within 7 days the main hoist before the load exceeds 1200 +/-

prior to the start 50 pounds.

of such operations with that hoist TSR 3.9.12.2.

Demonstrate operation of the overload cutoff on Within 7 days the frame-mounted and monorail-mounted prior to the start auxiliary hoists when the load exceeds 500 +/- 50 of such operations pounds.

with that hoist TSR 3.9.12.3.

Demonstrate operation of the normal uptravel Within 7 days stop interlock of the main hoist to maintain at prior to the start least 7 feet 11 inches of water coverage above of such operations the top of the active irradiated fuel.

with that hoist TSR 3.9.12.4.

Demonstrate operation of the normal uptravel Within 7 days stop interlock of the frame-mounted and prior to the start monorail-mounted auxiliary hoists to maintain of such operations at least 6 feet 9 inches of water coverage with that hoist above the top of the irradiated control rod.

(continued)

RIVER BEND Revision 70 TR 3.9-5 (13iii)

Control Rod Block Instrumentation TR 3.3.2.1 Table 3.3.2.1-1(Page 2 of 2)

Control Rod Block Instrumentation FUNCTION APPLICABLE REQUIRED CONDITIONS SURVEILLANCE NOMINAL ALLOWABLE MODES OR OTHER CHANNELS REFERENCED FROM REQUIREMENTS SETPOINT VALUE SPECIFIED PER TRIP TLCO REQUIRED CONDITIONS FUNCTION ACTION A.1 6.Source Range Monitors

a.

Detector not full in(e 2

3 B

TSR 3.3.2.1.12 NA NA TSR 3.3.2.1.16 5*

2**

C TSR 3.3.2.1.12 NA NA TSR 3.3.2.1.16

b.

Upscale"'1 2

3 B

TSR 3.3.2.1.12 1 x 10Scps

1.6 x TSR 3.3.2.1.16 10Scps 5*

2-C TSR 3.3.2.1.12 1 x 10Scps S 1.6 x TSR 3.3.2.1.16 10Scps

c.

Inoperative{f) 2 3

B TSR 3.3.2.1.12 NA NA

5.

2-C TSR 3.3.2.1.12 NA NA

d.

Downscale'9' 2

3 B

TSR 3.3.2.1.12

>0.7 cpsa

Ž 0.5 cps"'

TSR 3.3.2.1.16 5*

2-C TSR 3.3.2.1.12

>0.7 cps("

0.5 cps'i, TSR 3.3.2.1.16 7.Intermediate Range Monitors

a.

Detector not full in 2,

5-6 B

TSR 3.3.2.1.12 NA NA

b.

Upscale 2,

5*

6 B

TSR 3.3.2.1.12 108/125 S 110/125 TSR 3.3.2.1.16 division Of division of full scale full scale

c.

Inoperative 2,

5*

6 B

TSR 3.3.2.1.12 NA NA

d.

Downscale~h, 2,

5*

6 B

TSR 3.3.2.1.12 5/125

> 3/125 TSR 3.3.2.1.16 division of division of full scale full scale 8.Scram Discharge Volume

1. 2, 5*

2 D

TSR 3.3.2.1.13 Water level-high TSR 3.3.2.1.15 TSR 3.3.2.1.17

a.

LISN602A 18.00"

< 21.12"

b. LISN602B 18.00"

< 21.60" 9.Reactor Coolant System 1

2 D

TSR 3.3.2.1.13 114% of

117% of Recirculation Flow TSR 3.3.2.1.14 rated flow rated flow Upscale TSR 3.3.2.1.16 TSR 3.3.2.1.18 With any control rod withdrawn.

Not applicable to control rods removed per Technical Specification LCO 3.10.5 or 3.10.6.

OPERABLE channels must be associated with SRM required OPERABLE per Technical Specification LCO 3.3.1.2.

(a)

THERMAL POWER > HPSP.

(b)

THERMAL POWER > 35% RTP and

HPSP.

(c)

With THERMAL POWER ! 10% RTP.

(d)

Reactor mode switch in the shutdown position.

(e)

(f)

(g)

(h)

(i)

(j)

This function is not required if detector count rate is Ž l00 cps or the IRM channels are on range 3 or higher.

This function is not required when the associated IRM channels are on range 8 or higher.

This function is not required when the IRM channels are on range 3 or higher.

This function is not required when the IRM channels are on range 1.

Provided the Signal to noise ratio is Ž 2.0, otherwise trip setpoint of Ž3.0 cps and allowable Ž 1.8 cps.

Allowable Values and Nominal Values specified in COLR.

Allowable and nominal value modifications required by the COLR due to reduction in feedwater temperature may be delayed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

The trip setting for this Function must be maintained in accordance with TLCO 3.2.4.

ik) To address feedwater temperature reductions, set at first stage turbine pressure equivalent to 61.03 % RTP.

RIVER BEND TR 3.3-11 Revision 71 (18ii)

CRFA System Instrumentation TR 3.3.7.1 TR 3.3.7.1 Control Room Fresh Air (CRFA)

System Instrumentation Table 3.3.7.1-1 Control Room Fresh Air System Instrumentation FUNCTION APPLICABLE REQUIRED CONDITIONS SURVEILLANCE NOMINAL SETPOINT MODES OR CHANNELS REFERENCED REQUIREMENTS OTHER PER TRIP FROM SPECIFIED SYSTEM REQUIRED CONDITIONS ACTION A.1

1.

Reactor Vessel Water 1,2,3 2

B SR 3.3.7.1.1

-43 inches Level-Low Low, SR 3.3.7.1.2 Level 2 SR 3.3.7.1.3 SR 3.3.7.1.4 SR 3.3.7.1.5

2.

Drywell Pressure-1,2,3 2

C SR 3.3.7.1.1 1.68 psid High SR 3.3.7.1.2 SR 3.3.7.1.3 SR 3.3.7.1.4 SR 3.3.7.1.5

3.

Control Room 1,2,3 1

D SR 3.3.7.1.1 0.84 x 10-'

Ventilation Radiation (a), (b)

SR 3.3.7.1.2 Monitors (providing SR 3.3.7.1.4 ACi/cc initiation)

SR 3.3.7.1.5 (a)

During operations with a potential for draining the reactor vessel.

(b)

During movement of irradiated fuel assemblies in the primary containment or fuel building.

RIVER BEND TR 3.3-48 (71i)

Revision 71

RCS Pressure and Temperature (P/T) Limits(Vessel Hydro)

TR 3.4.11.1 TR 3.4.11 RCS Pressure and Temperature (P/T) Limits Note:

The pressure-temperature limits given in Technical Specification Figure 3.4.11-1 are limited for use up to 16 EFPY based on the NRC Safety Evaluation Report for Amendments 114 and 120.

Table 3.4.11-1 REACTOR VESSEL MATERIAL SURVEILLANCE PROGRAM WITHDRAWAL SCHEDULE CAPSULE WITHDRAWAL WITHDRAWAL TIME -

EFPY First 10.4 Second 15 Third Standby Table 3.4.11-2 REACTOR VESSEL MATERIAL SURVEILLANCE PROGRAM CAPSULE DATA CAPSULE VESSEL LEAD FACTOR NUMBER LOCATION at I.D./-T 1*

30 0.67/0.89 2

1770 0.67/0.89 3

1830 0.67/0.89

Note:

Capsule No.

1 was removed from and remained out of vessel during cycle 7.

This capsule is designated as the "standby" capsule.

RIVER BEND TR 3.4-10 (32ii)

Revision 71

RCS Pressure and Temperature (P/T) Limits(Vessel Hydro)

TR 3.4.11.1 TR 3.4.11.1 RCS Pressure and Temperature (P/T) Limits(Vessel Hydro)

TECHNICAL REQUIREMENT DELETED RIVER BEND TR 3.4-11 Revision 71 (32ii)

Control Rod Scram Accumulator Detectors/alarm Instrumentation TR 3.1.5.1 TR 3.1.5.1 Control Rod Scram Accumulator Detectors/alarm Instrumentation TLCO 3.1.5.1 APPLICABILITY:

Each control rod scram accumulator alarm shall be OPERABLE.

When associated control rod scram accumulator is OPERABLE per Technical Specification LCO 3.1.5.

ACTIONS

- NOTE Separate Condition entry is allowed for each control rod scram accumulator detector/alarm.

CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more accumulator A.1 Verify the affected Once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months pressure detectors or accumulator pressure alarms inoperable.

> 1540 psig.

B.

One or more accumulator B.1 Verify the affected Once per 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months leak detectors or alarms accumulator water drained.

inoperable.

AND Within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months prior to reactor startup C.

Required Action and A.1 Declare the associated Immediately associated Completion Time accumulator inoperable.

not met.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TSR 3.1.5.1.1 Perform a CHANNEL FUNCTIONAL TEST on the leak 18 months detector and associated alarm for each control rod scram accumulator.

TSR 3.1.5.1.2 Perform a CHANNEL CALIBRATION of the pressure 18 months detector for each control rod scram accumulator and verify a nominal alarm setpoint of 1600 psig on decreasing pressure.

RIVER BEND TR 3.1-3 (17ii)

Revision 72

RPS Instrumentation TR 3.3.1.1 Table 3.3.1.1-1 (page 2 of 3)

Reactor Protection System Instrumentation FUNCTION APPLICABLE REQUIRED CONDITIONS SURVEILLANCE NOMINAL SETPOINT/

MODES OR CHANNELS REFERENCED REQUIREMENTS RESPONSE TIME OTHER PER TRIP FROM SPECIFIED SYSTEM REQUIRED CONDITIONS ACTION D.1

2.

Average Power Range Monitors (continued)

c.

Fixed Neutron Flux-1 3

G SR 3.3.1.1.1 118% RTP High SR 3.3.1.1.2 SR 3.3.1.1.8 SR 3.3.1.1.9 SR 3.3.1.1.11 SR 3.3.1.1.15 S<00 e(d)

SR 3.3.1.1.18 0.09 sec

d.

Inop 1,2 3

H SR 3.3.1.1.8 NA SR 3.3.1.1.9 SR 3.3.1.1.15

3.

Reactor Vessel Steam Dome 1,2 2

H SR 3.3.1.1.1 1094.7 psig Pressure-High SR 3.3.1.1.9 SR 3.3.1.1.10 SR 3.3.1.1.13 SR 3.3.1.1.15 SR 3.3.1.1.18 TL < 0.35 sec (h)

4.

Reactor Vessel Water Level-1,2 2

H SR 3.3.1.1.1 9.7 inches

Low, Level 3 SR 3.3.1.1.9 SR 3.3.1.1.10 SR 3.3.1.1.13 SR 3.3.1.1.15 SR 3.3.1.1.18 TL < 1.05 sec(h)

5.

Reactor Vessel Water Level-

> 23.8% RTP 2

F SR 3.3.1.1.1 51 inches High, Level 8 (e)

SR 3.3.1.1.9 SR 3.3.1.1.10 SR 3.3.1.1.13 SR 3.3.1.1.15 SR 33.1..18(h)

SR 3.3.1.1.18 TL < 1.05 sec

6.

Main Steam Isolation Valve-1 8

G SR 3.3.1.1.9 8% closed SR 3.3.1.1.13 Closure (e)

SR 3.3.1.1.15 SR 3.3.1.1.18

- 0.09 sec

7.

Drywell Pressure-High 1,2 2

H SR 3.3.1.1.1 1.68 psid SR 3.3.1.1.9 SR 3.3.1.1.10 SR 3.3.1.1.13 SR 3.3.1.1.15 (continued)

(a),

(d)

(e)

(h)

(b),

(c),

(f),

(g) not used this page Response time shall be measured from the detector output or from the input to the first electronic component in the channel.

This function automatically bypassed with the reactor mode switch not in RUN.

TL = Tx

+ Tc; where:

TL = Measured total response time of the isolation system instrumentation T- = Hydraulic response time of the channel sensor measured upon initial installation Tc = Measured response time of the logic circuit excluding the channel sensor The given numerical value is the acceptance criterion for TL.

In case the sensor is replaced or refurbished, a hydraulic response time test must be performed to determine a revised value for T,.

RIVER BEND Revision 72 TR 3.3-3 (9ii)

ATWS-RPT Instrumentation TR 3.3.4.2 TR 3.3.4.2 Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT)

Instrumentation TABLE 3.3.4.2-1 ATWS RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION FUNCTION NOMINAL ALLOWABLE SETPOINT VALUE

1. Reactor vessel water 43 47 level -

Low Low Level INCHES INCHES 2

2.

Reactor Vessel 1153 PSIG

1165 PSIG Pressure High RIVER BEND Revision 72 TR 3.3-17 (31i)

Relief and Low -

Low Set Instrumentaiton TR 3.3.6.4 TR 3.3.6.4 Relief and Low-Low Set (LLS) Instrumentation Table 3.3.6.4-1 Relief and Low - Low set Instrumentation Valve F041A F047B FO41B (ADS)

FO51B F041F (ADS)

F047F F041C (ADS)

F051C F047C (ADS)

F051G (ADS)

F041G F047D F041D (ADS)

F051D F041L F047A (ADS)

Relief Setpoint"'

2) 1153 1143 1153 1143 1153 1143 1153 1143 1143 1143 1153 1143 1153 1133 1153 1143 Relief pressure switch N670 N669 N670

N669, N618 N670

N669, N617 N669

N669, N618 N670 N669 N670

N668, N616 N670 N669 Safety serpoint

, 3) 1195 1205 1195 1210 1195 1205 1195 1210 1205 1210 1195 1205 1195 1210 1195 1205 low -

low set lift setpoint 2, 2) 1143 1143 1103 1143 1063 low -

low set reclose setpoint11,21 976 976 966 976 956 (1) The lift setting pressure shall correspond to ambient conditions of the (1) The lift setting pressure shall correspond to ambient conditions of the valves at nominal operating temperatures and pressures.

(2)

The allowable values shall be within +/- 15 psig of listed setpoints.

(3)

The allowable values shall be within + 36 psig of listed setpoints.

RIVER BEND TR 3.3-45 (67i)

Revision 72

Control Rod Scram Accumulator Alarms -

Refueling TR 3.9.5.1 TR 3.9.5.1 Control Rod Scram Accumulator Alarms -

Refueling TLCO 3.9.5.1 APPLICABILITY:

Each control rod scram accumulator alarm shall be OPERABLE.

When associated control rod scram accumulator is OPERABLE per Technical Specification LCO 3.9.5.

ACTIONS

-NOTE Separate Condition entry is allowed for each control rod scram accumulator alarm.

CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more accumulator A.1 Verify the affected Once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months pressure detectors or accumulator pressure alarms inoperable.

> 1540 psig.

B.

One or more accumulator B.1 Verify the affected Once per 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months leak detectors or alarms accumulator water drained.

inoperable.

AND Within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months prior to reactor startup C.

Required Action and C.1 Declare the associated Immediately associated Completion accumulator inoperable.

Time not met.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TSR 3.9.5.1.1 Perform a CHANNEL FUNCTIONAL TEST on the leak 18 months detector and associated alarm for each control rod scram accumulator.

TSR 3.9.5.1.2 Perform a CHANNEL CALIBRATION of the pressure 18 months detector for each control rod scram accumulator and verify an nominal alarm setpoint of 1600 psig on decreasing pressure.

RIVER BEND TR 3.9-2 (7ii)

Revision 72

RCS Pressure and Temperature (P/T) Limits TR 3.4.11 TR 3.4.11 RCS Pressure and Temperature (P/T) Limits Note:

The pressure-temperature limits given in Technical Specification Figure 3.4.11-1 are limited for use up to 16 EFPY based on the NRC Safety Evaluation Report for Amendments 114 and 120.

Table 3.4.11-1 REACTOR VESSEL MATERIAL SURVEILLANCE PROGRAM WITHDRAWAL SCHEDULE CAPSULE WITHDRAWAL WITHDRAWAL TIME -

EFPY First 10.4 Second 15 Third Standby REACTOR VESSEL Table 3.4.11-2 MATERIAL SURVEILLANCE PROGRAM CAPSULE DATA CAPSULE VESSEL LEAD FACTOR NUMBER LOCATION at I.D./*T 1*

30 0.67/0.89 2

1770 0.67/0.89 3

1830 0.67/0.89

Note:

Capsule No.

1 was removed from and remained out of vessel during cycle 7.

This capsule is designated as the "standby" capsule.

RIVER BEND TR 3.4-10 (32i)

Revision 73

Primary Containment Air Locks TR 3.6.1.2 TR 3.6.1.2 Primary Containment Air Locks TLCO 3.6.1.2 DELETED RIVER BEND Revision 73 TR 3.6-3 (8i)

Primary Containment Air Lock Seal Air Flask Pressure instrumentation TR 3.6.1.2.1 TR 3.6.1.2.1 Primary Containment Air Lock Seal Air Flask Pressure instrumentation TLCO 3.6.1.2.1 APPLICABILITY:

Primary Containment Air Lock Seal Air Flask Pressure instrumentation channels shall be OPERABLE.

MODES 1, 2, 3,

During movement of recently irradiated the primary containment, During operations with a potential for vessel (OPDRVs).

fuel assemblies in draining the reactor ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

With one required A.1 Restore the channel to 7 days channel inoperable OPERABLE.

B.

Required Action and B.1 Perform Technical once per 12 associated completion Specification SR hours time not met 3.6.1.2.2 TR 3.6-4 (8iii)

RIVER BEND Revision 73

Electrical Equipment Protective Devices TR 3.8.11 TABLE 3.8.11-1 (page 6 of 7)

PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTION DEVICES C.

480 VAC Molded Case Circuit Breakers (continued)

3.

Gould Circuit Breaker Type HE43 (continued)

INHS-MCC8A 1NHS-MCC8A lNHS-MCC8A lNHS-MCC8B lNHS-MCC2F lNHS-MCC2F INHS-MCC2E lNHS-MCC2A lNHS-MCC2A 1NHS-MCC2B 1NHS-MCC8A 4C 6B 6C 2A 2A 2B 3C 3A 4A lC 3D

4.

Gould Circuit Breaker Type FVNR Size 3 Location lEHS*MCC2A IEHS*MCC2B 1NHS-MCC2B INHS-MCC2E 1NHS-MCC2E INHS-MCC2F INHS-MCC2F 1NHS-MCC2D JRB-RCPTI 1FNR-P06 1FNR-P08 1FNR-P07 1POP-WR2F01 1JRB-ELIA POP-WR2E01 1FNR-P09 lFNR-PI0 IFNR-PIl POP-WR8A01 Type A80 with Gould Starter/Controller Cubicle 2C 2C 2D 1D 6D 4D 6D 1E

5.

Gould Circuit Breaker Type 2SPlW Size 4 1NHS-MCC102A 1NHS-MCC102A 1NHS-MCC102A 1NHS-MCC102B 1NHS-MCC102B 1NHS-MCC102B IC 2C 3B IC 2C 3B

6.

Gould Circuit Breaker Type FVNR Size 2 INHS-MCC8B Equip.

No.

1C41*C001A IC41*COOIB 1C41*D003 1B33-D003A1 1B33-D003A4 IB33-DO03Bl 1B33-D003B4 1G36-C002 Type A80 with Gould Starter/Controller IDRS-UClA IDRS-UClC IDRS-UClE 1DRS-UClB 1DRS-UC1D 1DRS-UClF with Type A821 Gould Starter/Controller 1D 1F42-E001 (continued)

RIVER BEND TR 3.8-17 (42x)

Revision 73

Main Turbine Pressure Regulation System TR 3.2.5 TR 3.2 POWER DISTRIBUTION LIMITS TR 3.2.5 Main Turbine Pressure Regulation System TLCO 3.2.5 APPLICABILITY:

Both Main Turbine Steam Pressure Regulators shall be OPERABLE.

THERMAL POWER Ž 23.8% RTP.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One main turbine steam A.1 Establish the applicable 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months pressure regulator thermal limits per the inoperable.

COLR.

B.

Required Actions and B.1 Reduce THERMAL POWER to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months associated Completion

< 23.8% RTP.

Times not met.

TECHNICAL SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.2.5.1 Verify both main steam turbine pressure Once within 12 regulators are OPERABLE.

hours after

Ž 23.8% RTP AND 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter RIVER BEND TR 3.2-1 (6i)

Revision 74

Electrical Equipment Protective Devices TR 3.8.11 TABLE 3.8.11-1 (page 5 of 7)

PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTION DEVICES C.

480 VAC Molded Case Circuit Breakers (continued)

2.

Gould Circuit Breaker Type A822 with Gould Starter/Controller Type FVR Size 1 (continued)

Location Cubicle Equip.

No.

1EHS*MCC2K 1EHS*MCC2K 1EHS*MCC2K lEHS*MCC2K 1EHS*MCC2K 1EHS*MCC2K 1EHS*MCC2K 1EHS*MCC2K 1EHS*MCC2K 1NHS-MCC2A INHS-MCC2A 1NHS-MCC2A lNHS-MCC2A INHS-MCC2A INHS-MCC2B INHS-MCC2B INHS-MCC2B INHS-MCC2B 1NHS-MCC2B INHS-MCC2D lNHS-MCC2D lNHS-MCC2D 1NHS-MCC2E 1NHS-MCC2E 1NHS-MCC2F 1NHS-MCC8A

3.

Gould Circuit lNHS-MCC2A INHS-MCC2A 1NHS-MCC2A INHS-MCC2A lNHS-MCC2C lNHS-MCC2D INHS-MCC2D INHS-MCC8A INHS-MCC8A 2A 2B 2C 3D 4D 5A 6C 6D 7D IC 1D 5C 5D 7D 3B 3C 4D 5D 6D 2E 3D 4D 3A 5E 2D 4E Breaker 2B 2C 2D 3B ICT 5C 5D 1E 2D Type HE43 1RCS*MOV60B IRCS*MOV61B IHVN*MOV22B 1E12*MOVF042B IG33*MOVF053 1G33*MOVF040 IHVN*MOVI02 IEI2*MOVF037B lCCP*MOV158 IB21-MOVF001 1B33-MOVF023A 1G33-MOVFI02 1B33-MOVF067A IG33-MOVFI06 IG33-MOVF042 1B21-MOVF002 1G33-MOVF044 IG33-MOVFI00 1G33-MOVFI01 1B21-MOVF005 1B33-MOVF067B 1B33-MOVF023B IG33-MOVF031 1G33-MOVF107 1G33-MOVF104 lCll-MOVF003 1POP-WR2G01 1POP-WR2A01 1POP-WR2A02 1POP-WR2G02 IH22-PNLP008 1POP-WR2DO1 IPOP-WR2DO2 1F15-E006 1F15-E005 (continued)

RIVER BEND TR 3.8-16 (42ix)

Revision 74

Electrical Equipment Protective Devices TR 3.8.11 TABLE 3.8.11-1 (page 6 of 7)

PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTION DEVICES C.

480 VAC Molded Case Circuit Breakers (continued)

3.

Gould Circuit Breaker Type HE43 (continued) 1NHS-MCC8A 1NHS-MCC8A 1NHS-MCC8A 1NHS-MCC8B INHS-MCC2F 1NHS-MCC2F 1NHS-MCC2E 1NHS-MCC2A 1NHS-MCC2A 1NHS-MCC2B 1NHS-MCC8A 4C 6B 6C 2A 2A 2B 3C 3A 4A iC 3D

4.

Gould Circuit Breaker Type FVNR Size 3 Location lEHS*MCC2A 1EHS*MCC2B 1NHS-MCC2B INHS-MCC2E 1NHS-MCC2E 1NHS-MCC2F INHS-MCC2F INHS-MCC2D

5.

Gould Circuit Br Type 2SPIW Size 4 1NHS-MCC102A 1NHS-MCC102A 1NHS-MCC102A 1NHS-MCC102B 1NHS-MCC102B INHS-MCC102B JRB-RCPT1 1FNR-P06 1FNR-P08 1FNR-P07 lPOP-WR2F01 IJRB-ELIA POP-WR2E0l 1FNR-P09 IFNR-PlO IFNR-PII POP-WR8A01 Type A80 with Gould Starter/Controller Cubicle 2C 2C 2D 1D 6D 4D 6D 1E Equip.

No.

1C41*C001A IC41*COOlB 1C41*D003 1B33-D003Al 1B33-D003A4 1B33-DO03Bl 1B33-D003B4 IG36-C002 eaker Type A80 with Gould Starter/Controller IC 2C 3B IC 2C 3B

6.

Gould Circuit Breaker Type FVNR Size 2 IDRS-UClA IDRS-UClC IDRS-UClE IDRS-UClB IDRS-UClD IDRS-UClF Type A821 with Gould Starter/Controller INHS-MCC8B 1F42-E00l

7.

Gould Circuit Breaker Type FVR Size 2 lEHS*MCC2K 4A Type A822 with Gould Starter/Controller IEI2*MOVF009 (continued)

RIVER BEND TR 3.8-17 (42x)

Revision 74 1D

Relief and Low-Low Set Acoustic Monitor Instrumentation TR 3.3.6.4.1 TR 3.3.6.4.1 Relief and Low-Low Set (LLS)

Acoustic Monitor Instrumentation TLCO DELETED RIVER BEND Revision 75 TR 3.3-46 (67ii)

Relief and Low-Low Set Acoustic Monitor instrumentaiton TR 3.3.6.4.1 SURVEILLANCE REQUIREMENTS DELETED RIVER BEND TR 3.3-47 (67iii)

Revision 75

Offgas System Radiation Monitoring Instrumentation TR 3.3.7.8.2 TR 3.3.7.8.2 Offgas System Radiation Monitoring Instrumentation TLCO 3.3.7.8.2 APPLICABILITY:

ACTIONS The Offgas System Radiation Monitoring Instrumentation shown in Table T3.3.7.8.2-1 shall be OPERABLE with its alarm/trip setpoints within the specified limits.

During operation of the main condenser air ejector NOTE

1.

Separate Condition entry is allowed for each channel.

2.

The provisions of Technical Requirement TLCO 3.0.4 are not applicable.

CONDITION REQUIRED ACTION COMPLETION TIME A.

A radiation monitoring A.1 Adjust the setpoint to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months instrumentation channel within the limit.

alarm/trip setpoint exceeding the limit.

OR A.2 Declare the channel 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months inoperable.

B.

One or more radiation B.1 Enter the Condition Immediately monitoring channels Referenced in Table inoperable.

T3.3.7.8.2-1 for the channel.

C.

As required by Required C.1 Obtain a grab sample of Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Action B.1 and referenced the monitored parameter in Table T3.3.7.8.2-1.

AND C.2 Analyze the sample for Within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of gross radioactivity and sample collection verify effluent radioactivity is below trip setpoint.

AND C.3 Restore required 30 days instrumentation to OPERABLE status.

(continued)

RIVER BEND TR 3.3-69 (71xxii)

Revision 75

Offgas System Radiation Monitoring Instrumentation TR 3.3.7.8.2 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D.

As required by Required D.1 Verify by administrative Immediately Action B.1 and referenced means the required in Table T3.3.7.8.2-1.

Function l.a post treatment monitor is OPERABLE AND D.2 Verify the offgas system Immediately is not bypassed.

AND D.3 Restore required 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months instrumentation to OPERABLE status.

E Required Action and E.1 Enter TLCO 3.0.3 Immediately associated Completion Time for Conditions C or D not met.

SURVEILLANCE REQUIREMENTS NOTES------------------------------------

Refer to Table T3.3.7.8.2-1 to determine which TSRs apply to each channel.

SURVEILLANCE FREQUENCY TSR 3.3.7.8.2.1 Perform a CHANNEL CHECK.

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months TSR 3.3.7.8.2.2 Perform a CHANNEL FUNCTIONAL TEST.

92 days TSR 3.3.7.8.2.3 Perform a CHANNEL CALIBRATION.

18 months RIVER BEND TR 3.3-70 (71xxiii)

Revision 75

Offgas System Radiation Monitoring Instrumentation TR 3.3.7.8.2 TABLE T3.3.7.8.2-1 OFFGAS AND RADIATION MONITORING INSTRUMENTATION INSTRUMENTS MINIMUM CONDITIONS SURVEILLANCE NOMINAL ALLOWABLE INSTRUMENTS REFERENCED REQUIREMENTS SETPOINT UPPER LIMIT OPERABLE FROM REQUIRED ACTION 3.1 l.Main Condenser Offgas Post Treatment System Effluent Monitoring System

a.

Noble Gas Activity Monitor 1 (b)

C TSR 3.3.7.8.2.1 4.16 X 10s cpm 4.99 X iOl Providing Alarm and TSR 3.3.7.8.2.2 cpm Automatic Termination of TSR 3.3.7.8.2.3 Release) 2.Condenser Air Ejector Pretreatment Radioactivity Monitor

a.

Noble Gas Activity Monitor 1

D TSR 3.3.7.8.2.1 1.5 X Full (a)

TSR 3.3.7.8.2.2 Power Process TSR 3.3.7.8.2.3

Background

Radiation Level (alarm only)

(a)

The nominal setpoint of 1.5 times the full power process background radiation level shall not exceed a value corresponding to the Technical Specification LCO 3.7.4 allowable release rate.

(b)

For Item l.a., the monitoring system is provided with two detector channels. One detector may be in an inoperable, tripped condition, or placed in "inop" and the second detector remains capable of initiating the logic to isolate the system. However, a single inoperable detector may not be bypassed (e.g. jumpered out) without entering condition C.

RIVER BEND Revision 75 TR 3.3-71 (71xxiv)

Reactor Coolant System Pressure Isolation Valve Pressure Monitors TR 3.4.6.1 TR 3.4.6.1 Reactor Coolant System Pressure Isolation Valve Pressure Monitors TLCO 3.4.6.1 APPLICABILITY:

The high\\low pressure interface valve pressure monitors shown in Table 3.4.6.1-1 shall be OPERABLE.

MODES 1 and 2, MODE 3, except valves in the residual heat removal (RHR) shutdown cooling flowpath when in, or during the transition to or from, the shutdown cooling mode of operation.

ACTIONS NOTE O

Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more pressure A.1 Restore channel to 7 days monitors inoperable.

OPERABLE status.

B.

Required Action and B.1 Verify pressure less than once per associated Completion the alarm setpoint.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Time of Condition A not met.

AND B.2 Restore channel to 30 days OPERABLE status.

C.

Required Action and C.1 Enter TLCO 3.0.3 Immediately associated Completion Time of Condition B not met.

RIVER BEND TR3.4-7 (16ii)

Revision 75

Reactor Coolant System Pressure Isolation Valve Pressure Monitors TR 3.4.6.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TSR 3.4.6.1.1 Perform CHANNEL FUNCTIONAL TEST on the high/low 92 days pressure interface valves leakage pressure monitor alarm setpoints.

TSR 3.4.6.1.2 Perform CHANNEL CALIBRATION on the high/low 18 months pressure interface valves leakage pressure monitor setpoints per Table 3.4.6.1-1.

TABLE 3.4.6.1-1 REACTOR COOLANT SYSTEM INTERFACE VALVES LEAKAGE PRESSURE MONITORS NOMINAL ALARM INSTRUMENT NUMBER FUNCTION SETPOINT IE21*PTNO54 LPCS Pump Discharge Pressure High 580 psig IE22*PTNO52 HPCS Pump Suction Pressure High 80 psig IE12*PTNO53A RHR A Pump Discharge Pressure High 474 psig IEI2*PTNO53B RHR B Pump Discharge Pressure High 474 psig IE12*PTN053C RHR C Pump Discharge Pressure High 474 psig IEI2*PTNO57 RHR Pump Shutdown Cooling Suction 174 psig Pressure High RIVER BEND Revision 75 TR 3.4-8 (16iii)

Suppression Pool Pumpback System TR 3.5.4 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME E.

Required Action and E.1 Establish compliance with 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months associated Completion LCO 3.6.1.10, Primary Time for Condition C not Containment -

Shutdown.

met when suppression pool level is being maintained AND for LCO 3.5.2.

E.2.1.1 Provide an alternate 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months pumpback method AND E.2.1.2 Demonstrate the once per 24 OPERABILITY of an hours alternate pumpback thereafter method.

OR E.2.2.1 Suspend CORE Immediately ALTERATIONS AND E.2.2.2 Suspend operations Immediately with a potential for draining the reactor vessel (OPDRVs)

AND E.2.2.3 Lock the reactor mode Immediately switch in SHUTDOWN SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TSR 3.5.4.1 Perform a functional test of each crescent area sump 92 days pump to verify it is capable of developing 50 gpm when aligned to the suppression pool.

TSR 3.5.4.2 Verify the flow path can be aligned to the 92 days suppression pool.

RIVER BEND REVISION 75 TR 3.5-4 (12ii)

Gaseous Radwaste Treatment TR 3.11.2.4 TR 3.11.2.4 Gaseous Radwaste Treatment I SPECIFICATION DELETED Revision 75 RIVER BEND TR 3.1ii-10

AC Sources-Operating TR 3.8.1 TR 3.8 ELECTRICAL POWER SYSTEMS TR 3.8.1 AC Sources-Operating

NOTES-------------------------------

1.

The following surveillance requirements apply to Technical Specification LCO 3.8.1.

Failure to meet these surveillance requirements requires entry into Technical Specification LCO 3.8.1.

2.

When a modified DG start procedure is not used to satisfy SR 3.8.1.2, TSR 3.8.1.7 must be performed.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TSR 3.8.1.1 -

TSR 3.8.1.6 (Not Used)

TSR 3.8.1.7

NOTE--------------------

All DG starts may be preceded by an engine prelube period and followed by a warmup period prior to loading.

When each DG is started from standby As specified conditions for Technical Specification SR for SR 3.8.1.7 3.8.1.7:

a.

For DG 1A and DG lB, record whether the DG achieves at least 450 rpm in

10 seconds for trending.

b.

For DG IC record whether the DG achieves at least 882 rpm in

10 seconds for trending.

TSR 3.8.1.8 -

TSR 3.8.1.11 (Not Used)

(continued)

RIVER BEND Revision 76 TR 3.8-1 (15i)

AC Sources-Operating TR 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY TSR 3.8.1.13 TSR 3.8.1.18 (Not Used) 3.8.1.19 a.,

b.

(Not Used)

c.

When the DG is auto-started from standby condition for technical specification SR 3.8.1.19

1. -

4.

(Not Used)

5.

Verify the auto-connected loads for each diesel do not exceed 3130 KW for diesel generator 1A and 1B and 2600 KW for diesel generator IC.

18 months TSR 3.8.1.20 NOTE --------------

Once per 24 Not required to be met when Division III hours diesel engine is running.

OR Verify the Division III diesel generator ambient room temperature to be Ž 40'F Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months when the last reported room temperature

< 500 F.

TSR 3.8.1.21 (Deleted)

RIVER BEND Revision 76 TR 3.8-3 (15iii)

TSR I

AC Sources-Shutdown TR 3.8.2 SURVEILLANCE REQUIREMENTS

NOTE The following surveillance requirements apply to Technical Specification LCO 3.8.2.

Failure to meet these surveillance requirements requires entry into Technical Specification LCO 3.8.2.

SURVEILLANCE FREQUENCY TSR 3.8.2.1 NOTE--------------------

The following TSR is not required to be performed:

TSR 3.8.1.19.

For AC sources required to be OPERABLE, the following TSRs are applicable:

In accordance with applicable TSR 3.8.1.7 TSR 3.8.1.19 TSR 3.8.1.20 TSRs RIVER BEND Revision 76 TR 3.8-5 (20i)

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102 TSB-d RIVER BEND

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Battery Cell Parameters B 3.8.6 BASES SURVEILLANCE Table 3.8.6-1 (continued)

REQU IREMENTS Because of specific gravity gradients that are produced during the recharging process, delays of several days may occur while waiting for the specific gravity to stabilize.

A stabilized charger current is an acceptable alternative to specific gravity measurement for determining the state of charge.

This phenomenon is discussed in IEEE-450 (Ref. 3).

Footnote c to Table 3.8.6-1 allows the float charge current to be used as an alternate to specific gravity for up to 31 days following a battery recharge.

Within 31 days each connected cell's specific gravity must be measured to confirm the state of charge.

Following a minor battery recharge (such as equalizing charge that does not follow a deep discharge) specific gravity gradients are not significant, and confirming measurements may be made in less than 31 days.

REFERENCES

1.

USAR, Chapter 6.

2.

USAR, Chapter 15.

3.

IEEE Standard 450, 1987.

Revision No.

1 RIVER BEND B 3.8-69

inverters -

Operating B 3.8.7 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.7 Inverters -- Operating BASES BACKGROUND The inverters are the preferred source of power for the AC vital buses because of the stability and reliability they achieve.

There is one inverter per AC vital bus, making a total of two inverters.

The function of the inverter is to provide AC electrical power to the vital buses.

The inverters are powered from both AC and DC sources.

Specific details on inverters can be found in the USAR, Chapter 8 (Ref. 1).

APPLICABLE The initial conditions of Design Basis Accident (DBA)

SAFETY ANALYSES and transient analyses in the USAR, Chapter 6 (Ref.

2) and Chapter 15 (Ref. 3). assume Engineered Safety Feature systems are OPERABLE.

The inverters are designed to provide the required capacity, capability, redundancy, and reliability to ensure the availability of necessary power to portions of the ESF instrumentation and controls so that the fuel, Reactor Coolant System. and containment design limits are not exceeded.

These limits are discussed in more detail in the Bases for Section 3.2.

Power Distribution Limits: Section 3.4, Reactor Coolant System (RCS):

and Section 3.6, Containment Systems.

The OPERABILITY of the inverters is consistent with the initial assumptions of the accident analyses and is based on meeting the design basis of the unit.

This includes maintaining electrical power sources OPERABLE during accident conditions in the event of:

a.

An assumed loss of all offsite AC or all onsite AC electrical power: and

b.

A worst case single failure.

Inverters are a part of the distribution system and, as such, satisfy Criterion 3 of the NRC Policy Statement.

(continued)

Revision No. 6-1 RIVER BEND B 3.8-70

Inverters -

Operating B 3.8.7 BASES (continued)

LCO The inverters ensure the availability of AC electrical power for the instrumentation for the systems required to shut down the reactor and maintain it in a safe condition after an anticipated operational occurrence (AOO) or a postulated DBA.

Maintaining the required inverters OPERABLE ensures that the redundancy incorporated into the design of the ESF instrumentation and controls is maintained.

The two battery powered inverters ensure an uninterruptible supply of AC electrical power to the AC vital buses even if the 4.16 kV safety buses are de-energized.

OPERABLE inverters require that the associated vital bus is powered by the inverter via inverted DC voltage from the required Class 1E battery or from an internal AC source via a rectifier with the battery available as backup, with the output within the design voltage and frequency tolerances.

APPLICABILITY The inverters are required to be OPERABLE in MODES 1, 2, and 3 to ensure that:

a.

Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result of AOOs or abnormal transients: and

b.

Adequate core cooling is provided, and containment OPERABILITY and other vital functions are maintained in the event of a postulated DBA.

Inverter requirements for MODES 4 and 5 are covered in the Bases for LCO 3.8.8, "Inverters -- Shutdown."

ACTIONS With a required inverter inoperable, its associated AC vital bus is inoperable if not energized from one of its Class 1E voltage sources.

LCO 3.8.9 addresses this action: however, pursuant to LCO 3.0.6. these actions would not be entered even if the AC vital bus were de-energized.

Therefore, the ACTIONS are modified by a Note stating that ACTIONS for LCO 3.8.9 must be entered immediately.

This ensures the vital bus is re-energized within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

(continued)

Revision No. 6-1 RIVER BEND B 3.8-71

Inverters -Operating B 3.8.7 BASES ACTIONS A.1 (continued)

Required Action A.1 allows 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to fix the inoperable inverter and return it to service.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months limit is based upon engineering judgment, taking into consideration the time required to repair an inverter and the additional risk to which the plant is exposed because of the inverter inoperability.

This risk has to be balanced against the risk of an immediate shutdown, along with the potential challenges to safety systems that such a shutdown might entail.

When the AC vital bus is powered from one of its Class 1E sources, it is relying upon interruptible AC electrical power sources (offsite and onsite).

The uninterruptible inverter source to the AC vital buses is the preferred source for powering instrumentation trip setpoint devices.

B.1 and B.2 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 AC vital 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 AC vital buses.

The 7 day Frequency takes into account the redundant capability of the inverters and other indications available in the control room that alert the operator to inverter malfunctions.

(continued)

Revision No. 0 RIVER BEND 8 3.8-72

Inverters -Operating B 3.8.7 BASES (continued)

REFERENCES

1. USAR, Chapter 8.

2. USAR, Chapter 6.

3. USAR, Chapter 15.

RIVER BEND 3

Revision No.

0 8 3.8-73

Inverters -

Shutdown B 3.8.8 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.8 Inverters - Shutdown BASE S BACKGROUND A description of the inverters is provided in the Bases for LCO 3.8.7. "Inverters -- Operating."

APPLICABLE SAFETY ANALYSES The initial conditions of Design Basis Accident (DBA) and transient accident analyses in the USAR, Chapter 6 (Ref.

1) and Chapter 15 (Ref.

2). assume Engineered Safety Feature systems are OPERABLE.

The DC to AC inverters are designed to provide the required capacity, capability, redundancy, and reliability to ensure the availability of necessary power to portions of the ESF instrumentation and controls so that the fuel, Reactor Coolant System. and containment design limits are not exceeded.

The OPERABILITY of assumptions of the supported systems' the inverters is consistent with the initial accident analyses and the requirements for the OPERABILITY.

The OPERABILITY of the minimum inverters to each AC vital bus during MODES 4 and 5. and during movement of irradiated fuel assemblies in the primary containment or fuel building ensures that:

a.

The facility can be maintained in the shutdown or refueling cordition for extended periods;

b.

Sufficient instrumentation and control capability are available for monitoring and maintaining the unit status:

and

c.

Adequate power is available to mitigate events postulated during shutdown, such as an inadvertent draindown of the vessel or a fuel handling accident.

The inverters were previously identified as part of the Distribution System and, as such, satisfy Criterion 3 of the NRC Policy Statement.

(continued)

Revision No. 6-1 RIVER BEND B 3.8-74

Reactor Core SLs B 2.1.1 BASES SAFETY LIMIT VIOLATIONS REFERENCES 2.2.2 (continued) with the SL within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time ensures that the operators take prompt remedial action and also ensures that the probability of an accident occurring during this period is minimal.

2.2.3 If any SL is violated, the General Manager and the Vice President shall be notified 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 period provides time for plant operators and staff to take the appropriate immediate action and assess the condition of the unit before reporting to the senior management.

2.2.4 If any SL is violated, a Licensee Event Report shall be prepared and submitted within 30 days to the NRC in accordance with 10 CFR 50.73 (Ref. 5).

A copy of the report shall also be provided to the General Manager and the Vice President.

2.2.5 If any SL is violated, restart of the unit shall not commence until authorized by the NRC.

This requirement ensures the NRC that all necessary reviews, analyses, and actions are completed before the unit begins its restart to normal operation.

1.

10 CFR 50, Appendix A. GDC 10.

2.

NEDE-24011-P-A, "General Electric Standard Application for Reactor Fuel, GESTAR-II," (latest approved revision).

3.

10 CFR 50.72.

4.

10 CFR 100.

5.

10 CFR 50.73.

Revision No. 6-2 RIVER BEND B 2.0-5

RCS Pressure SL B 2.1.2 B 2.0 SAFETY LI*iITS-(SLs)

B 2.1.2 Reactor Coolant System (RCS)

Pressure SL BASES BACKGROUND APPLICABLE The RCS safety/relief valves and the Reactor Protection SAFETY ANALYSES System Reactor Vessel Steam Dome Pressure -High Function have settings established to ensure that the RCS pressure SL will not be exceeded.

(continued)

RIVER BEND The SL on reactor steam dome pressure protects the RCS against overpressurization.

In the event of fuel cladding failure, fission products are released into the reactor coolant.

The RCS then serves as the primary barrier in preventing the release of fission products into the atmosphere.

Establishing an upper limit on reactor steam dome pressure ensures continued RCS integrity.

According to 10 CFR 50. Appendix A. GDC 14, "Reactor Coolant Pressure Boundary," and GDC 15, "Reactor Coolant System Design" (Ref.

1), the reactor coolant pressure boundary (RCPB) shall be designed with sufficient margin to ensure that the design conditions are not exceeded during normal operation and anticipated operational occurrences (AOOs).

During normal operation and AOOs, RCS pressure is limited from exceeding the design pressure by more than 10%, in accordance with Section III of the ASME Code TRef. 2).

To ensure system integrity, all RCS components are hydrostatically tested at 125%

of design pressure, in accordance with ASME Code requirements, prior to initial operation when there is no fuel in the core.

Any further hydrostatic testing with fuel in the core may be done under LCO 3.10.1. "Inservice Leak and Hydrostatic Testing Operation."

Following inception of unit operation, RCS components shall be pressure tested in accordance with the requirements of ASME Code,Section XI (Ref. 3).

Overpressurization of the RCS could result in a breach of the RCPB, reducing the number of protective barriers designed to prevent radioactive releases from exceeding the limits specified in 10 CFR 100. "Reactor Site Criteria" (Ref. 4).

If this occurred in conjunction with a fuel cladding failure, fission products could enter the containment atmosphere.

B 2.0-6 Revision No.

0

RCS Pressure SL B 2.1.2 BASES APPLICABLE SAFETY ANALYSES (continued)

SAFETY LIMITS The RCS pressure SL has been selected such that it is at a pressure below which it can be shown that the integrity of the system is not endangered.

The reactor pressure vessel is designed to ASME, Boiler and Pressure Vessel Code.Section III, 1971 Edition. including Addenda through the summer of 1973 (Ref.

5). which permits a maximum pressure transient of 110%.

1375 psig, of design pressure 1250 psig.

The SL of 1325 psig. as measured in the reactor steam dome, is equivalent to 1375 psig at the lowest elevation of the RCS.

The RCS is designed to ASME Code, Section Ill, 1977 Edition, including Addenda through the summer of 1977 (Ref.

6). for the reactor recirculation piping.

which permits a maximum pressure transient of 110% of design pressures of 1250 psig for suction piping. 1650 psig for discharge piping between the pump and the discharge valve, and 1550 psig beyond the discharge valve.

The RCS pressure SL is selected to be the lowest transient overpressure allowed by the applicable codes.

The maximum transient pressure allowable in the RCS pressure vessel under the ASME Code.Section III. is 110% of design pressure.

The maximum transient pressure allowable in the RCS piping, valves, and fittings is 110% of design pressures of 1250 psig for suction piping, 1650 psig for discharge piping between the pump and the discharge valve, and 1550 psig beyond the discharge valve.

The most limiting of these allowances is the 110% of the suction piping design pressure: therefore, the SL on maximum allowable RCS pressure is established at 1325 psig as measured at the reactor steam dome.

APPLICABILITY SL 2.1.2 applies in all MODES.

SAFETY LIMIT 2.2.1 VIOLATIONS If any SL is violated, the NRC Operations Center must be notified within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . in accordance with 10 CFR 50.72 (Ref. 7).

(continued)

Revision No. 0 RIVER BEND B 2.0-7

RCS Pressure SL B 2.I2 BASES SAFETY LIMIT VIOCLATIONS (continued) 2.2.2 Exceeding the RCS pressure SL may cause immediate RCS failure and create a potential for radioactive releases in excess of 10 CFR 100, "Reactor Site Criteria," limits (Ref. 4),

Therefore, it is required to insert all insertable control rods and restore compliance with the SL within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time ensures that the operators take prompt remedial action and also ensures that the probability of an accident occurring during this period is minimal.

2.2.3 If any SL is violated, the General Manager and the Vice President shall be notified 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 period provides time for plant operators and staff to take the appropriate immediate action and assess the condition of the unit before reporting to the senior management.

2.2.4 If any SL is violated, a Licensee Event Report shall be prepared and submitted within 30 days to the NRC in accordance with 10 CFR 50.73 (Ref. 8).

A copy of the report shall also be submitted to the General Manager and the Vice President.

2.2.5 If any SL is violated, restart of the unit shall not commence until authorized by the NRC.

This requirement ensures the NRC that all necessary reviews, analyses, and actions are completed before the unit begins its restart to normal operation.

(continued)

Revision No. 6-2 RIVER BEND B 2.0-8

PAM instrumentatlon B 3.3.3.1 BASES LCO

6.

Orywell Pressure (continued)

Drywell pressure is a Category I variable provided to detect breach of the RCPB and to verify ECCS functions that operate to maintain RCS integrity.

Two wide range drywell pressure signals are transmitted from separate pressure transmitters and are continuously recorded and displayed on two control room recorders.

These recorders are the primary indication used by the operator during an accident.

Therefore, the PAM Specification deals specifically with this portion of the instrument channel.

7.

Primary Containment Pressure Primary containment pressure is a Category I variable provided to verify RCS and containment integrity and to verify the effectiveness of ECCS actions taken to prevent containment breach.

Two wide range primary containment pressure signals are transmitted from separate pressure transmitters and are continuously recorded and displayed on two control room recorders.

These recorders are the primary indication used by the operator during an accident.

Therefore, the PAM Specification deals specifically with this portion of the instrument channel.

8. Drywell Area Radiation (Hiqh Ranqe)

Drywell area radiation (high range) is a Category I variable provided to monitor for the potential of significant radiation releases and to provide release assessment for use by operators in determining the need to invoke site emergency plans.

Drywell area radiation (high range) PAM instrumentation consists of two high range drywell area radiation signals transmitted from separate radiation elements and continuously displayed on two control room LED digital displays.

The RM-23 control and display modules are the primary indication used by the operator during an accident.

Therefore, the PAM Specification deals specifically with this portion of the instrument channel.

(continued)

Revision No. 6-2 RIVER BEND B 3.3-53

PAM instrumenzation B 3.3.3.

BASES LCO

9.

Primary Containment Area Radiation (High Range)

(continued)

Primary containment area radiation (high range) is a Category 1 variable provided to monitor for the potential of significant radiation releases and to provide release assessment for use by operators in determining the need to invoke site emergency plans.

Primary containment area radiation (high range) PAM instrumentation consists of two high range containment area radiation signals transmitted from separate radiation elements and continuously displayed on two control room LED digital displays.

The RM-23 control and display modules are the primary indication used by the operator during an accident.

Therefore.

the PAM Specification deals specifically with this portion of the instrument channel.

10,

11.

Drywell and Containment Hydroqen Analyzer Drywell and containment hydrogen analyzers are Category I instruments provided to detect high hydrogen concentration conditions that represent a potential for containment breach.

This variable is also important in-verifying the adequacy of mitigating actions.

The drywell and containment hydrogen analyzers PAM instrumentation consists of containment and drywell hydrogen concentration signals transmitted from two separate hydrogen analyzers and recorded on two two-pen recorders in the control room.

One pen records the hydrogen concentration and one pen records the sample point on each of the two independent recorders.

Measurement capability is provided over the range of 0 to 10 percent hydrogen concentration using a sample drawing system.

12.

Penetration Flow Path, Automatic Primary Containment Isolation Valve (PCIV)

Position PCIV position is provided for verification of containment integrity.

In the case of PCIV position, the important information is the status of the containment penetration flow path.

The LCO requires one channel of valve position indication in the control room to be OPERABLE for each automatic PCIV in a containment penetration flow path, i.e.,

(continued)

RIVER BEND B 3.3-54 Revision No. 6-2

SCIDs B 3.6A4 2 BASES (continued)

REFERENCES

1.

USAR, Section 15.6.5.

2.

USAR. Section 6.2.3.

3.

USAR. Section 15.7.4.

4.

TRM. Table 3.6.4.2-1.

Revision No. 6-2 B 3.6-95 RIVER BEND

SGT System S 36,46 3

B 3.6 CONTAINMENT SYSTEMS B 3.6.4 3 Standby Gas Treatment (SGT) System BASES BACKGROUND The SGT System is required by 10 CFR 50, Appendix A, GDC 41.

"Containment Atmosphere Cleanup" (Ref.

1).

The function of the SGT System is to ensure that radioactive materials that leak from the primary containment into the secondary containment following a Design Basis Accident (DBA) are filtered and adsorbed prior to exhausting to the environment.

The SGT System consists of two fully redundant subsystems, each with its own set of ductwork, dampers, charcoal filter train, and controls.

Each charcoal filter train consists of (components listed in order of the direction of the air flow):

a.

A moisture separator;

b.

An electric heater;

c.

A prefilter:

d.

A high efficiency particulate air (HEPA) filter:

e.

A charcoal adsorber:

f.

A second HEPA filter: and

g.

A centrifugal fan.

The SGT System serves as a backup non-ESF system to the Annulus Pressure Control System (APCS) during normal operation.

Upon loss of the APCS, or upon an ESF signal (i.e.,

LOCA).

the annulus air and air from the shielded compartments in the auxiliary building are automatically diverted through the SGT System filter trains.

(continued)

Revision No. 0 RIVER BEND B 3.6-96

Drywell Isolation valves B 3-6.5.3 B ASES URVELILANCE SR 3.6.5.3.4 REQU:REMENTS

-qtued) 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

i. 2. and 3.

Therefore, the probability of misalignment of these devices, once they have been verified to be in their proper position, is low.

A second Note is included to clarify that the drywell isolation valves that are open under administrative controls are not required to meet the SR during the time that the devices are open.

Verifying that the isolation time of each power operated and each automatic drywell isolation valve is within limits is required to demonstrate OPERABILITY.

The isolation time test ensures the valve will isolate in a time period less than or equal to that assumed in the safety analysis.

The isolation time and Frequency of this SR are in accordance with the Inservice Testing Program.

SR 3.6.5.3.5 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 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power, since isolation of penetrations would eliminate cooling water flow and disrupt the normal operation of many critical components.

Operating experience has shown these components usually pass this Surveillance when performed at the 18 month Frequency.

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

SR 3.6.5.3.6 This SR ensures that the hydrogen mixing valves remain closed during Modes 1, 2. and 3. or, if open, are only open for a limited period of time over a 365 day cycle.

Since (continued)

Revision No. 2-8 B 3.6-13S RIVER BEND

Drywell Isolation Valves B 3,65.3 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.6.5.3.6 the hydrogen mixing isolation valves have never been demonstrated capable of closing under accident conditions in the drywell. this SR applies restrictions to the opening of these valves (Reference 3).

The frequency of this SR is consistent with the frequency of SR 3.6.3.2 and allows the administrative tracking of the hours open to be performed concurrently with the isolation valve closure verification.

REFERENCES

1.

USAR, Section 6.2.4.

2.

USAR.

Table 6.2-51.

3.

CR 96-0767.

Revision No-6-2 RIVER BEND B 3.6-136

AC Sources -Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.16 (continued)

REQUIREMENTS

2)

Post corrective 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 Under accident conditions. loads are sequentially connected to the bus by the load sequencing logic.

The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading of the bus power supply due to high motor starting currents.

The 10% load sequence time tolerance ensures that sufficient time exists for the bus power supply to restore frequency and voltage prior to applying the next load and that safety analysis assumptions regarding ESF equipment time delays are not violated.

(Note that this surveillance requirement pertains only to the load sequence-timer itself, and not to the interposing logic which comprises the remainder of the circuit.)

Reference 2 provides a summary of the automatic loading of ESF buses.

The Frequency of 18 months is consistent with the recommendations of Regulatory Guide 1.108 (Ref. 9), paragraph 2.a.(2); takes into consideration plant conditions required to perform the Surveillance: and is intended to be consistent with expected fuel cycle lengths.

This SR is modified by a Note.

The reason for the Note is that performing the Surveillance during these MODES 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 (continued)

Revision No. 6-2 RIVER BEND B 3.8-29

AC Sources -Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.17 (continued)

REQUIREMENTS

2)

Post corrective 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 3.8.1.18 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.

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 Frequency of 18 months takes into consideration plant conditions required to perform the Surveillance and is intended to be consistent with an expected fuel cycle length of 18 months.

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, that is, with the engine coolant and oil being continuously circulated and temperature maintained consistent with manufacturer recommendations for DG 1A and DG lB.

For DG 1C, 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.

The reason for Note 2 is that performing the Surveillance would remove a required offsite circuit from (continued)

Revision No. 0 RIVER BEND B 3.8-30

Reactor

-Cre SLs 82.1.!

BASES APPLICABLE 2.1.1.1 Fuel Cladding Integrity (continued)

SAFETY ANALYSES indicate that the fuel assembly critical power at this flow is approximately 3.35 MWt.

With the design peaking factors, this corresponds to a THERMAL POWER

> 50% of original RTP.

Thus. a THERMAL POWER limit of 23.8% RTP for reactor pressure < 785 psig is conservative.

2.1.1.2 MCPR The fuel cladding integrity SL is set such that no significant fuel damage is calculated to occur if the limit is not violated.

Since the parameters that result in fuel damage are not directly observable during reactor operation, the thermal and hydraulic conditions that result in the onset of transition boiling have been used to mark the beginning of the region in which fuel damage could occur.

Although it is recognized that the onset of transition boiling would not result in damage to BWR fuel rods.

the critical power at which boiling transition is calculated to occur has been adopted as a convenient limit.

However, the uncertainties in monitoring the core operating state and in the procedures used to calculate the critical power result in an uncertainty in the value of the critical power.

Therefore. the fuel cladding integrity SL is defined as the critical power ratio in the limiting fuel assembly for which more than 99.9% of the fuel rods in the core are expected to avoid boiling transition.

considering the power distribution within the core and all uncertainties.

The MCPR SL is determined using a statistical model that combines all the uncertainties in operating parameters and the procedures used to calculate critical power.

The probability of the occurrence of boiling transition is determined using the approved General Electric critical power correlations.

Details of the fuel cladding integrity SL calculation are given in Reference 2.

Reference 2 also includes a tabulation of the uncertainties used in the determination of the MCPR SL and of the nominal values of the parameters used in the MCPR SL statistical analysis.

(continued)

RIVER BEND KeVislon No.

0-4

Reactor Core SLs B 2.1.1 BASES APPLICABLE SAFETY ANALYSES (continued)

SAFETY LIMITS APPLICABILITY SAFETY LIMIT VIOLATIONS 2.1.1.3 Reactor Vessel Water Level During MODES I and 2, the reactor vessel water level is required to be above the top of the active fuel to provide core cooling capability.

With fuel in the reactor vessel during periods when the reactor is shut down, consideration must be given to water level requirements due to the effect of decay heat.

If the water level should drop below the top of the active irradiated fuel during this period, the ability to remove decay heat is reduced.

This reduction in cooling capability could lead to elevated cladding temperatures and clad perforation in the event that the water level becomes less than two-thirds of the core height.

The reactor vessel water level SL has been established at the top of the active irradiated fuel to provide a point that can be monitored and to also provide adequate margin for effective action.

The reactor core SLs are established to protect the integrity of the fuel clad barrier to the release of radioactive materials to the environs.

SL 2.1.1.1 and SL 2.1.1.2 ensure that the core operates within the fuel design criteria.

SL 2.1.1.3 ensures that the reactor vessel water level is greater than the top of the active irradiated fuel in order to prevent elevated clad temperatures and resultant clad perforations.

SLs 2.1.1.1, 2.1.1.2, and 2.1.1.3 are applicable in all MODES.

If any SL is violated, the NRC Operations Center must be notified within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , in accordance with 10 CFR 50.72 (Ref. 3).

2.2.2 Exceeding an SL may cause fuel damage and create a potential for radioactive releases in excess of 10 CFR 100, "Reactor Site Criteria," limits (Ref. 4).

Therefore, it is required to insert all insertable control rods and restore compliance (conti nued)

Revision No. 0 RIVER BEND B 2.0-4

APLHGR B 3.2.1 B 3.2 POWER DISTRIBUTION LIMITS B 3.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)

BASES BACKGROUND APPLICABLE SAFETY ANALYSES The APLHGR is a measure of the average LHGR of all the fuel rods in a fuel assembly at any axial location.

Limits on the APLHGR are specified to ensure that the fuel design limits identified in Reference 2 are not exceeded during anticipated operational occurrences (AOOs) and that the peak cladding temperature (PCT) during the postulated design basis loss of coolant accident (LOCA) does not exceed the limits specified in 10 CFR 50.46.

The analytical methods and assumptions used in evaluating the fuel design limits are presented in the USAR, Chapters 4, 6, and 15, and in References 1 and 2.

The analytical methods and assumptions used in evaluating Design Basis Accidents (DBAs),

anticipated operational transients, and normal operations that determine APLHGR limits are presented in USAR, Chapters 4, 6, and 15, and in References 1, 2, 3, and 4.

Fuel design evaluations are performed to demonstrate that the 1% limit on the fuel cladding plastic strain and other fuel design limits described in Reference I are not exceeded during AOOs for operation with LHGR up to the operating limit LHGR.

APLHGR limits are developed as a function of exposure and the various operating core flow and power states to ensure adherence to fuel design limits during the limiting AOOs.

A complete discussion of the analysis code is provided in Reference 5.

LOCA analyses are then performed to ensure that the above determined APLHGR limits are adequate to meet the PCT and maximum oxidation limits of 10 CFR 50.46.

The analysis is performed using calculational models that are consistent with the requirements of 10 CFR 50, Appendix K. A complete discussion of the analysis code is provided in Reference 6.

The PCT following a postulated LOCA is a function of the average heat generation rate of all the rods of a fuel assembly at any axial location and is not strongly (continued)

RIVER BEND Revision No. 0 B 3.2-1

APL!GR B 3. 2.

BASES SAFE>y AN.ARES (cont n-er Influenced by the rod to rod power distr bution within an assembly.

The APLHGR limits specified are equivalent to the iiGR of the hignest powered fuel rod assumed in the LOCA analysis

¢' rded by its local peaking factor.

A conservative multiplier is applied to tne LHGR assumed in the LOCA analysis to account for the uncertainty associated with the measurement of the APLHGR.

For single recirculation loop operation, a conservative (i.e

1.0) multiplier, specified in the COLR. is applied to the APLHGR limit.

This multiplier is due to the conservative analysis assumption of an earlier departure from nucleate boiling with one recirculation loop available, resulting in a more severe cladding heatup during a LOCA.

The APLHGR satisfies Criterion 2 of the NRC Policy Statement.

LCO The APLHGR limits specified in the COLR are the result of fuel

design, DBA.

and transient analyses.

For two recirculat.on foods operating, the limit is determined by the exposure dependent APLHGR limits.

With only one recirculation loop in operation, in conformance with the requirements of LCO 3.4.1, "Recirculation Loops Operating." the limit is determined by multiplying the exposure dependent APLHGR limit by a value determined by a specific single recirculation loop analysis.

APPLICABILITY The APLHGR limits are primarily derived from fuel design evaluations and LOCA and transient analyses that are assumed to occur at high power levels.

Design calculations and operating experience have shown that as power is reduced, the margin to the required APLHGR limits increases.

This trend continues down to the power range of 5% to 15% RTP when entry into MODE 2 occurs.

When in MODE 2, the intermediate range monitor (IRM) scram function provides prompt scram initiation during any significant transient, thereby effectively removing any APLHGR limit compliance concern in MODE 2.

Therefore, at THERMAL POWER levels

< 23.8% RTP. the reactor operates with substantial margin to the APLHGR limits: thus. this LCO is not required.

(continued)

RIVER BEND B 3.2-2 Revision No.

6-4

APLHGR B 3.2. 1 BASES (continued)

ACTIONS A.1 If any APLHGR exceeds the required limit, an assumption regarding an initial condition of the DBA and transient analyses may not be met.

Therefore, prompt action is taken to restore the APLHGR(s) to within the required limit(s) such that the plant will be 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 sufficient to restore the APLHGR(s) to within its limit and is acceptable based on the low probability of a transient or DBA occurring simultaneously with the APLHGR out of specification.

B.1 If the APLHGR 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

< 23.8% 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 oper'-ting experience, to reduce THERMAL POWER to < 23.8% RTP in.* 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 a 23.8% RTP and then every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on both engineering judgment and recognition of the slowness of changes in power distribution under normal conditions.

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance after THERMAL POWER

, 23.8% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels.

REFERENCES

1.

NEDE-24011-P-A, "General Electric Standard Application for Reactor Fuel, GESTAR-It" (latest approved revision).

2.

USAR. Chapter 4, Appendix 4B.

(continued)

Revision No.

6-4 RIVER BEND B 3.2-3

APLHGR B 3.2.1 BASES REFERENCES

3.

USAR, Chapter 15, Appendix 15B.

(continued)

4.

NEDO-30130-A, "Steady State Nuclear Methods,"

May 1985.

5.

NEDO-24154, "Qualification of the One-Dimensional Core Transient Model for Boiling Water Reactors," October 1978.

6.

NEDE-23785-1-P, "The GESTR-LOCA and SAFER Models for the Evaluation of the Loss-of-Coolant Accident,"

Volumes 1, II & III, December 1981.

Revision No.

3-7 RIVER BEND 8 3.2-4

MCPR 8 3.2.2 B 3.2 POWER DISTRIBUTION LIMITS B 3.2.2 MINIMUM CRITICAL POWER RATIO (MCPR)

BASES BACKGROUND MCPR is a ratio of the fuel assembly power that would result in the onset of boiling transition to the actual fuel assembly power.

The MCPR Safety Limit (SL) is set such that 99.9% of the fuel rods avoid boiling transition if the limit is not violated (refer to the Bases for SL 2.1.1.2).

The operating limit MCPR is established to ensure that no fuel damage results during anticipated operational occurrences (AOOs).

Although fuel damage does not necessarily occur if a fuel rod actually experiences boiling transition (Ref.

1),

the critical power at which boiling transition is calculated to occur has been adopted as a fuel design criterion.

The onset of transition boiling is a phenomenon that is readily detected during the testing of various fuel bundle designs.

Based on these experimental data, correlations have been developed to predict critical bundle power (i.e.,

the bundle power level at the onset of transition boiling) for a given set of plant parameters (e.g., reactor vessel pressure, flow, and subcooling).

Because plant operating conditions and bundle power levels are monitored and determined relatively easily, monitoring the MCPR is a convenient way of ensuring that fuel failures due to inadequate cooling do not occur.

APPLICABLE SAFETY ANALYSES The analytical methods and assumptions used in evaluating the AOOs to establish the operating limit MCPR are presented in the USAR, Chapters 4, 6, and 15, and References 2, 3, and

4.

To ensure that the MCPR SL is not exceeded during any transient event that occurs with moderate frequency, limiting transients have been analyzed to determine the largest reduction in critical power ratio (CPR).

The types of transients evaluated are loss of flow, increase in pressure and power, positive reactivity insertion, and coolant temperature decrease.

The limiting transient yields the largest change in CPR (ACPR).

When the largest ACPR is added to the MCPR SL, the required operating limit MCPR is obtained.

(conti nued)

Revision No. 0 RIVER BEND 8 3.2-5

S32 2 BASES APPL :CABLE SAFETY ANALYSES

( -o nt:, n!.,ed )

L(CQ The MCPR operatirg 11mits derived from the transient analys-s are deoendent on the operating core flow and power state *MCPRf and MCPR,.

respectively) to ensure adherence to fuel design limits during the worst transient that occurs with moderate frequency.

Flow dependent MCPR limits (MCPRf) are cetermined by steady state thermal hydraulic methods using the tnree Oimensional BWR simulator code (Ref. 5).

MCPRf curves are provided based on the maximum credible flow runout transient for Non Loop Manual operation.

Non Loop Manual operation bounds Loop Manual because Non Loop Manual operation can result in a more severe flow runout transient.

The result of a single failure or single operator error during Loop Manual operation is the runout of only one loop because both recirculation loops are under independent control.

Non Loop Manual operational modes allow simultaneous runout of both loops because a single controller regulates core flow.

Power dependent MCPR limits (MCPRQ ) are determined by the three dimensional BWR simulator code and the one dimensional transient code (Ref. 6).

Due to the sensitivity of the transient response to initial core flow levels at power levels below those at which the turbine stop valve closure and turbine control valve fast closure scram trips are bypassed, high and low flow MCPRQ operating limits are provided for operating between 23.8% RTO and the previously mentioned bypass power level The MCPR satisfies Criterion 2 of the NRC Policy Statement.

The MCPR operating limits specified in the COLR are the result of the Design Basis Accident (DBA) and transient analysis.

The MCPR operating limits are determined by the larger of the MCPRf and MCPRQ limits.

APPLICABILITY The MCPR operating limits are primarily derived from transient analyses that are assumed to occur at high power levels.

Below 23.8% RTP, the reactor is operating at a slow recirculation pump speed and the moderator void ratio is small.

Surveillance of thermal limits below 23.8% RTP is unnecessary due to the large inherent margin that ensures that the MCPR SL is not exceeded even if a limiting transient occurs.

Studies of the variation of limiting transient behavior have (continued)

Revision No. 6-4 RIVER BEND B 3.2-6

B 3. 2. 2 BASES APPLICABILITY (continued)

ACTIONS been performed over the range of power and flow conditions.

These studies encompass the range of key actual plant parameter values important to typically limiting transients. The results of these studies demonstrate that a margin is expected between performance and the MCPR requirements. and that margins increase as power is reduced to 23.8% RTP.

This trend is expected to continue to the 5% to 15% power range when entry into MODE 2 occurs.

When in MODE 2, the intermediate range monitor (IRM) provides rapid scram initiation for any significant power increase transient, which effectively eliminates any MCPR compliance concern.

Therefore. at THERMAL POWER levels

< 23.8% RTP, the reactor is operating with substantial margin to the MCPR limits and this LCO is not required.

A. 1.

If any MCPR is outside the required limit, an assumption regarding an initial condition of the design basis transient analyses may not be met.

Therefore, prompt action should be taken to restore the MCPR(s) to within the required limit(s) such that the plant remains operating within analyzed conditions.

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 MCPR(s) to within its limit and is acceptable based on the low probability of a transient or DBA occurring simultaneously with the MCPR out of specification.

B.1 If the MCPR cannot be restored to within the 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

< 23.8% 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 < 23.8% RTP in an orderly manner and without challenging plant systems.

(continued)

Revision No.

6-4 RIVER BEND B 3.2-7

MC2R B3.22 BASES (continued)

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 23-8% RTP and then every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter.

It is compared to the specified limits in the COLR to ensure that the reactor is operating within the assumpt-ons of the safety analysis.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on both engineering judgment and recognition of the slowness of changes in power distribution during normal operation.

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months aliowance after THERMAL POWER reaches

Ž 23.8% RTP is acceptable given the large inherent margin to operating limits at low power levels.

REFERENCES

1.

NUREG-0562.

"Fuel Rod Failures As A Consequence of Nucleate Boiling or Dry Out," June 1979.

2.

NEDE-24011-P-A.

"General Electric Standard Application for Reactor Fuel.

GESTAR-1I" (latest approved revision).

3.

USAR, Chapter 4. Appendix 4B.

4 USAR, Chapter 15. Appendix 152.

5 NEDO-30130-A.

"Steady State Nuclear Methods,"

May 1985.

6 NEDO-24154. "Qualification of the One-Dimensional Core Transient Model for Boiling Water Reactors." October 1978.

Revision No. 6-4 RIVER BEND B 3.2-8

LHGR B 3.2.3 B 3.2 POWER DISTRIBUTION LIMITS B 3.2.3 LINEAR HEAT GENERATION RATE (LHGR)

BASES BACKGROUND APPLICABLE SAFETY ANALYSES The LHGR is a measure of the heat generation rate of a fuel rod in a fuel assembly at any axial location.

Limits on the LHGR are specified to ensure that fuel design limits are not exceeded anywhere in the core during normal operation, including anticipated operational occurrences (AOOs).

Exceeding the LHGR limit could potentially result in fuel damage and subsequent release of radioactive materials.

Fuel design limits are specified to ensure that fuel system damage, fuel rod failure or inability to cool the fuel does not occur during the anticipated operating conditions identified in USAR Chapters 6 and 15.

The analytical methods and assumptions used in evaluating the fuel system design are presented in the USAR, Chapters 4, 6, and 15, and in References 1 and 2.

The fuel assembly is designed to ensure (in conjunction with the core nuclear and thermal hydraulic design, plant equipment, instrumentation, and protection system) that fuel damage will not result in the release of radioactive materials in excess of the guidelines of 10 CFR, Parts 20, 50, and 100.

The mechanisms that could cause fuel damage during operational transients and that are considered in fuel evaluations are:

a.

Rupture of the fuel rod cladding caused by strain from the relative expansion of the U02 pellet; and

b.

Severe overheating of the fuel rod cladding caused by inadequate cooling.

A value of 1% plastic strain of the fuel cladding has been defined as the limit below which fuel damage caused by overstraining of the fuel cladding is not expected to occur (Ref. 3).

Fuel design evaluations have been performed and demonstrate that the 1% fuel cladding plastic strain design limit is not exceeded during continuous operation with LHGRs up to the (continued)

Revision No.

0 RIVER BEND B 3.2-9

BASES APPLICABLE operating limit specified in the COLR.

The analysis also SAFETY ANALYSES includes allowances for snort term transient operation above (contirued) the operating !imit to account for AO0s, plus an allowance for densification power spiking.

The LHGR satisfies C-rterion 2 of the NRC Policy Statement LCO The LHGR is a basic assumption in the fuel design analysis.

The fuel has been designed to operate at rated core power with sufficient design margin to the LHGR calculated to cause a 1%

fuel cladding plastic strain.

The operating limit to accomplish this objective is specified in the COLR.

APPLICABILITY The LHGR limits are derived from fuel design analysis that is limiting at high power level conditions.

At core thermal power levels < 23.8% 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 Ž 23.8% 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 or Design Basis Accident 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 < 23.8% RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

The allowed (continued)

Revision No.

6-4 RTVER REND B 3.2-10

832.3 BASES ACTIONS B-1 (continued)

Completion Time Is reasonable, based on operating experience, to reduce THERMAL POWER to < 23.8% 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 : 23.8% RTP and then every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on both engineering judgment and recognition of the slowness of changes in power distribution under normal conditions.

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance after THERMAL POWER

Ž23.8% RTP is achieved is acceptable given the large inherent margin to operating limits at lower power levels.

REFERENCES

1.

NEDE-24011-P-A.

"General Electric Standard Application for Reactor Fuel, GESTAR-II' (latest approved revision).

2.

USAR, Chapter 4, Appendix 4B.

3.

NUREG-0800, "Standard Review Plan." Section 4.2, II.A.2(g).

Revision 2. July 1981.

RIVER BEND 0

.-4 1 Revision No. 6-4

8ASES B 3,3.1.r APPLICABLE 2.a.

Average Power Range Monitor Neutron Flux-High, SAFETY ANALYSES.

Setdown (continued)

LCO.

and APPLICABILITY With the IRMs at Range 9 or 10, it is possible that the Average Power Range Monitor Neutron Flux-High. Setdown Function will Provide the primary trip signal for a corewide increase in power.

No specific safety analyses take direct credit for the Average Power Range Monitor Neutron Flux-High. Setdown Function.

However, this Function indirectly ensures that, before the reactor mode switch is placed in the run position. reactor power does not exceed 23.8% RTP (SL 2.1.1.1) when operating at low reactor pressure and low core flow.

Therefore. it indirectly prevents fuel damage during significant reactivity increases with THERMAL POWER < 23.8% RTP.

The APRM System is divided into two groups of channels with four APRM channel inputs to each trip system.

The system is designed to allow one channel in each trip system to be bypassed.

Any one APRM channel in a trip system can cause the associated trip system to trip.

Six channels of Average Power Range Monitor Neutron Flux-High, Setdown. with three channels in each trip system are required to be OPERABLE to ensure that no single failure will preclude a scram from this Function on a valid signal.

In addition, to provide adequate coverage of the entire core, at least 11 LPRM inputs are required for each APRM channel.

with at least two LPRM inputs from each of the four axial levels at which the LPRMs are located.

The Allowable Value is based on preventing significant increases in power when THERMAL POWER is < 23.8% RTP.

The Average Power Range Monitor Neutron Flux-High, Setdown Function must be OPERABLE during MODE 2 when control rods may be withdrawn since the potential for criticality exits.

In MODE 1.

the Average Power Range Monitor Neutron Flux-High Function provides protection against reactivity transients and the RWL and RPC protect against control rod withdrawal error events.

(continued)

RIVER BEND Dl-,,

ci j-Revision No.

6-4

RPS Instrumentation BASES APPLICABLE 4

Reactor Vessel Water Level-Low, Level 3 (continued)

SAFETY ANALYSES.

LCO. and The Function is required in MODES I and 2 where considerable APPL'CABiL7TY energy exists in the RCS resulting in the limiting transients and accidents.

ECCS initiations at Reactor Vessel Water Level-Low Low. Level 2 and Low Low Low. Level I provide sufficient protection for level transients in all other MODES.

5.

Reactor Vessel Water Level-High, Level 8 High RPV water level indicates a potential problem with the feedwater level control system. resulting in the addition of reactivity associated with the introduction of a significant amount of relatively cold feedwater.

Therefore, a scram is initiated at Level 8 to ensure that MCPR is maintained above the MCPR SL.

The Reactor Vessel Water Level-High, Level 8 Function is one of the many Functions assumed to be OPERABLE and capable of providing a reactor scram during transients analyzed in Reference 3.

It is directly assumed in the analysis of feedwater controller failure, maximum demand (Ref.

4).

Reactor Vtbssel Water Level-High. Level 8 signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel.

The Reactor Vessel Water Level-High, Level 8 Allowable Value is specified to ensure that the MCPR SL is not violated during the assumed transient.

Four channels of the Reactor Vessel Water Level-High. Level 8 Function, with two channels in each trip system arranged in a one-out-of-two logic, are available and are required to be OPERABLE when THERMAL POWER is 23.8% RTP to ensure that no single instrument failure will preclude a scram from this Function on a valid signal.

With THERMAL POWER < 23.8% RTP. this Function is not required since MCPR is not a concern below 23.8% RTP.

(continued)

Revision No. 6-4 RIVER BEND B 3.3-13

RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES,

LCO, and APPLICABILITY (continued)

6.

Main Steam Isolation Valve-Closure MSIV closure results in loss of the main turbine and the condenser as a heat sink for the Nuclear Steam Supply System and indicates a need to shut down the reactor to reduce heat generation.

Therefore, a reactor scram is initiated on a Main Steam Isolation Valve-Closure signal before the MSIVs are completely closed in anticipation of the complete loss of the normal heat sink and subsequent overpressurization transient.

However, for the overpressurization protection analysis of Reference 2, the Average Power Range Monitor Fixed Neutron Flux-High Function, along with the S/RVs, limits the peak RPV pressure to less than the ASME Code limits.

That is, the direct scram on position switches for MSIV closure events is not assumed in the overpressurization analysis.

Additionally, MSIV closure is assumed in the transients analyzed in Reference 4 (e.g., low steam line pressure, manual closure of MSIVs, high steam line flow).

The reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the ECCS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.

MSIV closure signals are initiated from position switches located on each of the eight MSIVs.

Each MSIV has two position switches; one inputs to RPS trip system A while the other inputs to RPS trip system B.

Thus, each RPS trip system receives an input from eight Main Steam Isolation Valve-Closure channels, each consisting of one position switch.

The logic for the Main Steam Isolation Valve-Closure Function is arranged such that either the inboard or outboard valve on three or more of the main steam lines (MSLs) must close in order for a scram to occur.

The Main Steam Isolation Valve-Closure Allowable Value is specified to ensure that a scram occurs prior to a significant reduction in steam flow, thereby reducing the severity of the subsequent pressure transient.

Sixteen channels of the Main Steam Isolation Valve-Closure Function with eight channels in each trip system are required to be OPERABLE to ensure that no single instrument failure will preclude the scram from this Function on a valid signal.

This Function is only required in MODE 1 since, with the MSIVs open and the heat generation rate high, a pressurization transient can occur if the MSIVs (continued)

RIVER BEND B 3.3-14 Revision No.

0

RPS Instrumentation B 3.3.1.1 BASES (continued)

SURVEILLANCE SR 3.3.1.1.2 REQUIREMENTS (continued)

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 Frequency of once per 7 days is based on minor changes in LPRM sensitivity, which could affect the APRM reading between performances of SR 3.3.1.1.8.

A restriction to satisfying this SR when < 23.8% RTP is provided that requires the SR to be met only at 23.8% RTP because it is difficult to accurately maintain APRM indication of core THERMAL POWER consistent with a heat balance when < 23.8% RTP.

At low power levels, a high degree of accuracy is unnecessary because of the large inherent margin to thermal limits (MCPR and APLHGR).

At 23.8% RTP. the Surveillance is required to have been satisfactorily performed within the last 7 days in accordance with SR 3.0.2.

A Note is provided which allows an increase in THERMAL POWER above 23.8% if the 7 day 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 23.8% RTP.

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

SR 3.3.1.1.3 The Average Power Range Monitor Flow Biased Simulated Thermal Power-High Function uses a trip level generated by the flow control trip reference card based on the recirculation loop drive flow.

The drive flow is adjusted by a digital algorithm according to selected drive flow alignment dip switch settings.

This SR sets the flow control trip reference card to ensure the drive flow alignment used results in the appropriate trip level being generated from the digital components of the card.

The Frequency of once following a refueling outage is based on the expectation that any change in the core flow to drive flow functional relationship during power operation would be gradual and (continued)

Revision No. 6-4 RIVER BEND B 3.3-25

Primary Containment and Drywell Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE

1. Main Steam Line Isolation SAFETY ANALYSES,

LCO, and l.a.

Reactor Vessel Water Level -Low Low Low, Level 1 APPLICABILITY (continued)

Low reactor pressure vessel (RPV) water level indicates that the capability to cool the fuel may be threatened.

Should RPV water level decrease too far, fuel damage could result.

Therefore, isolation of the MSIVs and other interfaces with the reactor vessel occurs to prevent offsite dose limits from being exceeded.

The Reactor Vessel Water Level--Low Low Low, Level I Function is one of the many Functions assumed to be OPERABLE and capable of providing isolation signals.

The Reactor Vessel Water Level--Low Low Low, Level I Function associated with isolation is assumed in the analysis of the recirculation line break (Ref.

1).

The isolation of the MSL on Level 1 supports actions to ensure that offsite dose limits are not exceeded for a DBA.

Reactor vessel water level signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel.

Four channels of Reactor Vessel Water Level-Low Low Low, Level 1 Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The Reactor Vessel Water Level--Low Low Low, Level I Allowable Value is chosen to be the same as the ECCS Level 1 Allowable Value (LCO 3.3.5.1) to ensure that the MSLs isolate on a potential loss of coolant accident (LOCA) to prevent offsite doses from exceeding 10 CFR 100 limits.

This Function isolates the Group 6 valves.

1.b.

Main Steam Line Pressure-Low Low MSL pressure indicates that there may be a problem with the turbine pressure regulation, which could result in a low reactor vessel water level condition and the RPV cooling down more than 100OF/hour if the pressure loss is allowed to continue.

The Main Steam Line Pressure-Low Function is directly assumed in the analysis of the pressure regulator failure (Ref. 2).

For this event, the closure of the MSIVs ensures that the RPV temperature change limit (100°F/hour)

(continued)

Revision No. 0 RIVER BEND 8 3.3-139

Prlmary Containment and Drywell Isolation Tnstrumentatlen 33.3.61 EASES APPLICABLE 1 b Main Steam Line Pressjre-Low (continued)

SAFETY ANALYSES.

,1 a

is no: reacned in addition, this Function supports actions APPL:2.ABIjTY to ensure that Safety Limit 2.1.1.1 is not exceeded.

(This

-unctlon closes the MSIVs prior to pressure decreasing below 785 psig, which results in a scram due to MSIV closure, thus recucing reactor power to < 23.8% RTP.)

The MSL low pressure signals are initiated from four transmitters that are connected to the MSL header.

The transmitters are arranged such that. even though physically secarated from each other, each transmitter is able to detect low MSL pressure.

Four channels of Main Steam Line Pressure-Low Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The Allowable Value was selected to be high enough to prevent excessive RPV depressurization.

The Main Steam Line Pressure-Low Function is only required to be OPERABLE in MODE I since this is when the assumed transient can occur (Ref.

2).

This Function isolates the Group 6 valves.

1.c.

Main Steam Line Flow-High Main Steam Line Flow-High is provided to detect a break of the MSL and to initiate closure of the MSIVs.

If the steam were allowed to continue flowing out of the break, the reactor would depressurize and the core could uncover.

If the RPV water level decreases too far, fuel damage could occur.

Therefore, the isolation is initiated on high flow to prevent or minimize core damage.

The Main Steam Line Flow-High Function is directly assumed in the analysis of the main steam line break (MSLB) accident (Ref.

1).

The isolation action, along with the scram function of the RPS. ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46 and offsite doses do not exceed the 10 CFR 100 limits.

The MSL flow signals are initiated from 16 transmitters that are connected to the four MSLs.

The transmitters are arranged such that, even though physically separated from (continued)

Revision No. 6-4 RIVER BEND B 3.3-140

Recirculation Loops Operating B 3.4.1 BASES APPLICABLE The recirculation system is also assumed to have sufficient SAFETY ANALYSES flow coastdown characteristics to maintain fuel thermal (continued) margins during abnormal operational transients (Ref.

2). which are analyzed in Chapter 15 of the USAR.

A plant specific LOCA analysis has been performed assuming only one operating recirculation loop.

This analysis has demonstrated that. in the event of a LOCA caused by a pipe break in the operating recirculation loop, the Emergency Core Cooling System response will provide adequate core cooling, provided the APLHGR requirements are modified accordingly (Ref.

3).

The transient analyses of Chapter 15 of the USAR have also been performed for single recirculation loop operation (Ref. 3) and demonstrate sufficient flow coastdown characteristics to maintain fuel thermal margins during the abnormal operational transients analyzed provided the MCPR requirements are modified.

During single recirculation loop operation, modification to the Reactor Protection System average power range monitor (APRM) instrument setpoints is also required to account for the different relationships between recirculation drive flow and reactor core flow.

The APLHGR and MCPR limits for single loop operation are specified in the COLR.

The APRM flow biased simulated thermal power setpoint is in LCO 3.3.1.1, "Reactor Protection System (RPS)

Instrumentation."

Recirculation loops operating satisfies Criterion 2 of the NRC Policy Statement.

LCO Two recirculation loops are normally required to be in operation with their flows matched within the limits specified in SR 3.4.1.1 to ensure that during a LOCA caused by a break of the piping of one recirculation loop the assumptions of the LOCA analysis are satisfied.

Alternatively, with only one recirculation loop in operation. THERMAL POWER must be ! 79% RTP.

the total core flow limitations identified above must be met, modifications to the required APLHGR limits (LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)"),

MCPR limits (LCO 3.2.2. "MINIMUM (continued)

Revision No.

6-4 RIVER BEND B 3.4-3

ML021050303

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