Text

Revisions to the Technical Requirements Manual and the Technical Specification Bases
	ML17201Q131
Person / Time
Site:	River Bend
Issue date:	07/20/2017
From:	Maguire W; Entergy Operations
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	RBF1-17-0082, RBG-47775
	Download: ML17201Q131 (53)
	v • d • e

Entergx RBG-47775 July 20, 2017 U. S. Nuclear Regulatory Commission Document Control Desk Washington, D. C. 20555

Subject:

Revisions to the Technical Requirements Manual and the Technical Specification Bases River Bend Station - Unit 1 Docket No. 50-458 License No. NPF-47 RBF1-17-0082

Dear Sir or Madam:

Pursuant to 10 CFR 50.71 (e), Entergy Operations, Inc., (EOI) herein submits changes to the River Bend Station (RBS) Technical Requirements Manual (TRM). The revised pages cover the changes made during the period of August 7, 2015 through July 20, 2017. This includes TRM revisions 142 through 144.

Pursuant to RBS Technical Specification (TS) 5.5.11, revised pages for the Technical Specification (TS) Bases pages are included. The revised pages reflect the changes made during the same period stated above. This includes TS Bases revisions 162 through 168, excluding revision 165. An administrative error resulted in that number being skipped.

As required by 10 CFR 50.71 (e), the affirmation below certifies that the information in this submittal accurately reflects changes made since the previous submittal, as necessary to represent information and analyses submitted or prepared pursuant to NRC requirements.

If you have any questions, please call Tim Schenk at 225-381-4177. I declare under penalty of perjury that the foregoing is true and correct. Executed on July 20,2017.

Sincerely, WFM/dhw

Enclosures:

1. Technical Requirements Manual Revision Pages

2. Technical Specifications Bases Revision Pages

RBG-47775 July 20, 2017 Page 2 of 2 cc: U. S. Nuclear Regulatory Commission Region IV 1600 E. Lamar Blvd.

Arlington, TX 76011-4125 Department of Environmental Quality Office of Environmental Compliance Radiological Emergency Planning and Response Section Ji Young Wiley P.O. Box 4312 Baton Rouge, LA 70821-4312 Central Records Clerk Public Utility Commission of Texas Austin, TX (w/o enclosures)

Senior Resident Inspector River Bend Station Ms. Lisa Regner U. S. Nuclear Regulatory Commission Washington, DC

Enclosure 1 RBG-47775 Technical Requirements Manual Revision Pages

TECHNICAL REQUIREMENTS MANUAL LIST OF EFFECTIVE PAGES PAGE NUMBER REV PAGE NUMBER REV PAGE NUMBER REV i 77 TR 3.3-28 (52ii) 5 TR 3.3-74 (74i) 136 ii 100 TR 3.3-29 (52iii) 5 TR 3.3-75 (77i) 90 iii 98 TR 3.3-30 (52iv) 116 TR 3.3-76 (77ii) 5 iv 139 TR 3.3-31 (52v) 128 TR 3.3-77 (77iii) 44 v 141 TR 3.3-32 (57i) 133 TR 3.3-78 (77iv) 128 vi 77 TR 3.3-33 (57ii) 97 TR 3.3-79 (77v) 131 TR 1-1 77 TR 3.3-34 (57iii) 133 TR 3.3-80 (77vi) 131 TR 1-2 77 TR 3.3-35 (57iv) 133 TR 3.3-81 (77vii) 5 TR 1-3 77 TR 3.3-36 (57v) 13 TR 3.3-82 (77viii) 5 TR 1-4 135 TR 3.3-37 (57vi) 87 TR 3.3-83 (77ix) 128 TR 3.0-1 115 TR 3.3-38 (57vii) 132 TR 3.3-84 (77x) 5 TR 3.0-2 115 TR 3.3-39 (57viii) 28 TR 3.3-85 (77xi) 5 TR 3.0-3 92 TR 3.3-40 (60i) 62 TR 3.3-86 (77xii) 77 TR 3.0-4 115 TR 3.3-41 (60ii) 62 TR 3.3-87 (77xiii) 5 TR 3.1-1 (10i) 5 TR 3.3-42 (61i) 62 TR 3.3-88 86 TR 3.1-2 (17i) 128 TR 3.3-43 (61ii) 98 TR 3.3-89 90 TR 3.1-3 (17ii) 128 TR 3.3-44 (65i) 9 TR 3.3-90 (40i) 103 TR 3.1-4 . (25i) 5 TR 3.3-45 (67i) 72 TR 3.4-1 (4i) 5 TR 3.2-1 (6i) 74 TR 3.3-46 (67ii) 75 TR 3.4-2 (5i) 48 TR 3.3-1 (6i) 127 TR 3.3-47 (67iii) 75 TR 3.4-3 (5ii) 86 TR 3.3-2 (9i) 48 TR 3.3-48 (71i) 85 TR 3.4-4 (11i) 5 TR 3.3-3 (9ii) 142 TR 3.3-49 (7lii) 91 TR 3.4-5 (13i) 5 TR 3.3-4 (9iii) 78 TR 3.3-50 (71iii) 128 TR 3.4-6 (16i) 127 TR 3.3-5 (lSi) 5 TR 3.3-51 (71iv) 38 TR 3.4-7 (16ii) 107 TR 3.3-6 (15ii) 5 TR 3.3-52 (71v) 38 TR 3.4-8 (16iii) 128 TR 3.3-7 (17i) 5 TR 3.3-53 (71vi) 77 TR 3.4-9 (19i) 128 TR 3.3-8 (17ii) 18 TR 3.3-54 (71vii) 128 TR 3.4-10 (32i) 101 TR 3.3-9 (17iii) 128 TR 3.3-55 (71viii) 5 TR 3.4-11 (32ii) 71 TR 3.3-10 (18i) 61 TR 3.3-56 (71ix) 79 TR 3.4-12 (32iii) 5 TR 3.3-11 (18ii) 86 TR 3.3-57 (71x) 5 TR 3.4-13 (33i) 5 TR 3.3-12 (24i) 5 TR 3.3-58 (71xi) 40 TR 3.4-14 (33ii) 5 TR 3.3-13 (24ii) 109 TR 3.3-59 (71xii) 5 TR 3.4-15 (33iii) 39 TR 3.3-14 (24iii) 109 TR 3.3-60 (71xiii) 40 TR 3.4-16 (33iv) 5 TR 3.3-15 (24iv) 109 TR 3.3-61 (71xiv) 40 TR 3.4-17 (33v) 5 TR 3.3-16 (28i) 127 TR 3.3-62 (71xv) 106 TR 3.5-1 (5i) 5 TR 3.3-17 (3li) 72 TR 3.3-63 ('71xvi) 128 TR 3.5-2 (5ii) 5 TR 3.3-18 (37i) 5 TR 3.3-64 (71xvii) 119 TR 3.5-3 (12i) 77 TR 3.3-19 (43i) 9 TR 3.3-65 (71xviii) 67 TR 3.5-4 (12ii) 128 TR 3.3-20 (43ii) 9 TR 3.3-66 (71xix) 122 TR 3.6-1 (2i) 11 TR 3.3-21 (43iii) 9 TR 3.3-67 (71xx) 51 TR 3.6-2 (2ii) 108 TR 3.3-22 (43iv) 9 TR 3.3-68 (71xxi) 51 TR 3.6-3 (8i) 73 TR 3.3-23 (43v) 9 TR 3.3-69 (71xxii) 128 TR 3.6-3a (8ii) 13 TR 3.3-24 (43vi) 77 TR 3.3-70 (71xxiii) 128 TR 3.6-4 (8iii) 73 TR 3.3-25 (43vii) 128 TR 3.3-71 (71xxiv) 90 TR 3.6-5 (20i) 11 TR 3.3-26 (47i) 9 TR 3.3-72 (71xxv) 26 TR 3.6-6 (20ii) 77 TR 3.3-27 (52i) 116 TR 3.3-73 (71xxvi) 5 RIVER BEND TR-a Revision 142

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 1 3 G SR 3.3.1.1.1 118% RTP Flux - 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 (d)

SR 3.3.1.1.18 S 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 1,2 2 H SR 3.3.1.1.1 1094.7 psig Dome 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 (h)

SR 3.3.1.1.18 TL S 0.35 sec

4. Reactor Vessel Water 1,2 2 H SR 3.3.1.1.1 9.7 inches Level 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 (h)

SR 3.3.1.1.18 TL S 1. 05 sec

5. Reactor Vessel Water ~ 23.8% RTP 2 F SR 3.3.1.1.1 51 inches Is}

Level High, Level 8 SR 3.3.1.1.9 SR 3.3.1.1.10 SR 3.3.1.1.13 SR 3.3.1.1.15 (h)

SR 3.3.1.1.18 TL S 1.05 sec

6. Main Steam Isolation 1 8 G SR 3.3.1.1.9 8% closed Ie}

Valve - Closure SR 3.3.1.1.13 SR 3.3.1.1.15 SR 3.3.1.1.18 S 0.15 sec

7. Drywell Pre.ssure High I, 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), (b), (c), (f), (g) not used this page (d) Response time shall be measured from the detector output or from the input to the first electronic component in the channel.

(e) This function automaticallY bypassed with the reactor mode switch not in RUN.

(h) TL ~ Tx + Tel where:

TL ~ Measured total response time of the isolation system instrumentation Tx ~ 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 Tx.

RIVER BEND TR 3.3-3 Revision 142 (9ii)

TECHNICAL REQUIREMENTS MANUAL LIST OF EFFECTIVE PAGES PAGE NUMBER REV PAGE NUMBER REV PAGE NUMBER REV i 77 TR 3.3-28 (52ii) 5 TR 3.3-74 (74i) 136 ii 100 TR 3.3-29, (52iH) 5 TR 3.3-75 (77i) 90 iii 98 TR 3.3-30 (52iv) 116 TR 3.3-76 . (77ii) 5 iv 139 TR 3.3-31 (52v) 128 TR 3.3-77 (77iH) 44 V 141 TR 3.3-32 (57i) 133 TR 31,3-78 (77iv) 128 vi 77 TR 3.3-33 (57ii) 97 TR 3.3-79 (77v) 131 TR 1-1 77 TR 3.3-34 (57iH) 133 TR 3.3-80 (77vi) 131 TR 1-2 77 TR 3.3-35 (57iv) 133 TR 3.3-81 (77vii) 5 TR 1-3 77 TR 3.3-36 (57v) 13 TR 3.3-82 (77viii) 5 TR 1-4 135 TR 3.3-37 (57vi) 87 TR 3.3-83 (77ix) 128 TR 3.0-1 115 TR 3.3-38 (57vii) 132 TR 3.3-84 (77x) 5 TR 3.0-2 115 TR 3.3-39 (57viii) 28 TR 3.3-85 (77xi) 5 TR 3.0-3 92 TR 3.3-40 (60i) 62 TR 3.3-86 (77xii) 77, TR 3.0-4 115 TR 3.3-41 (60H) 62 TR 3.3-87 (77xiii) 5 TR 3.1-1 (10i) 5 TR 3.3-42 (61i) 62 TR 3.3-88 86 TR 3.1-2 (17i) 128 TR 3.3-43 (61ii) 98 TR 3.3-89 90 TR 3.1-3 (17ii) i28 TR 3.3-44 (65i) 9 TR 3.3-90 (40i) 103 TR 3.1-4 (25i) 5 TR 3.3-45 (67i) 72 TR 3.4-1 (4i) 5 TR 3.2-1 (6i) 74 TR 3.3-46 (67H) 75 TR 3.4-2 (5i) 48 TR 3.3-1 (6i) 127 TR 3.3-47 (67iii) 75 TR 3.4-3 (5ii) 86 TR 3.3-2 (9i) 48 TR 3.3-48 (71i) 85 TR 3.4-4 (l1i) 5 TR 3.3-3 (9ii) 142 TR 3.3-49 (71ii) 91 TR 3.4-5 (13i) 5 TR 3.3-4 (9iii) 78 TR 3.3-50 (71iii) 128 TR 3.4-6 (16i) 127 TR 3.3-5 (lSi) 5 TR 3.3-51 (71iv) 38 TR 3.4-7 (16ii) 107 TR 3 .. 3.-6 (lSii) 5 TR 3.3-52 (7iv) 38 TR 3.4-8 (16iii) 128 TR 3.3-7 (17i) 5 TR 3.3-53 (71vi) 77 TR 3.4-9 (19i) 128 TR 3.3-8 . (17ii) 18 TR 3.3-54 (71vii) 128 TR 3.4-10 (32i) 101 TR 3.3-9 (17iii) 128 TR 3.3-55 (71viii) 5 TR 3.4-11 (32ii) ?l TR 3.3-10 (18i) 61 TR 3.3-56 (71ix) 79 TR 3.4-12 (32iii) 5 TR 3.3-11 (18ii) 86 TR 3.3-t57 (71x) 5 TR 3.4-13 (33i) 5 TR 3.3-12 (24i) 5 TR 3.3-58 (?lxi) 40 TR 3.4-14 (33ii) 5 TR 3.. 3-13 (24ii) 109 TR 3.3-59 (?lxii) 5 TR 3.4-15 (33iii) 39 TR 3.3-14 (24iH) 109 TR 3.3-60 (?lxiii) 40 TR 3.4-16 (33iv) 5 TR 3.3-15 (24iv) 109 TR 3.3-61 (?lxiv) 40 . TR 3.4-17 (33v) 5 TR 3.3-16 (28i) 127 . TR 3.3-62 (?lxv) 106 TR 3.5-1 (5i)< 5 TR 3.3-17 (31i) 72 TR 3.3-63 (7lx:vi) 128 TR 3.5-2 (5ii) 5 TR 3.3-18 (37i) 5 TR 3.3-64 (?lxvii) 119 TR 3.5-3 (12i) 77 TR 3.3-19 (43i) 9 TR 3.3-65 (71xviii) 67 TR 3.5-4 (12ii) 128 TR 3.3-20 (43ii) 9 TR 3.3-66" (?lxix) 122 TR 3.6-1 (2i) 11 TR 3.3-21 (43iii) 9 TR 3.3-67 (?lxx) 51 TR 3.6-2 (2ii) 108 TR 3.3-22 (43iv) 9 TR 3.3-68 (?lxxi) 51 TR 3.6-3 (8i) 73 TR 3.3-23 (43v) 9 TR 3.3-69 (7lxxii) 128 TR 3.6-3a (8ii) 143 TR 3.3-24 (43vi) 77 TR 3.3-70 (71xxiii) 128 TR 3.6-4 (8iii) 73 TR 3.3-25 (43vii) 128 TR 3.3-71 (?lxxiv) 90 TR 3.6-5 (20i) 11 TR 3.3-26 (47i) 9 TR 3.3-72 (71xxv) 26 TR 3.6-6 (20ii) 77 TR 3.3-27 (52i) 116 TR 3.3-73 (71xxvi) 5 RIVER BEND TR-a Revision 143

RIVER BEND' TR 3.6".38. ,Rev-lsion 143 8i:i.).,

TECHNICAL REQUIREMENTS MANUAL LIST OF EFFECTIVE PAGES PAGE NUMBER REV PAGE NUMBER REV PAGE NUMBER REV i 77 TR 3.3-28 (52ii) 5 TR 3.3-74 (74i) 136 ii 100 TR 3.3-29 (52iii) 5 TR 3.3-75 (77i) 90 iii 98 TR 3.3-30 (52iv) 116 TR 3.3-76 (77ii) 5 iv 139 TR 3.3-31 (52v) 128 TR 3.3-77 (77iii) 44 v 141 TR 3.3-32 (57i) 133 TR 3.3-78 (77iv) 128 vi 77 TR 3.3-33 (57ii) 97 TR 3.3-79 (77v) 131 TR 1-1 77 TR 3.3-34 (57iii) 133 TR 3.3-80 (77vi) 131 TR 1-2 77 TR 3.3-35 (57iv) 133 TR 3.3-81 (77vii) 5 TR 1-3 77 TR 3.3-36 (57v) 13 TR 3.3-82 (77viii) 5 TR 1-4 135 TR 3.3-37 (57vi) 87 TR 3.3-83 (77ix) 128 TR 3.0-1 115 TR 3.3-38 (57vii) 132 TR 3.3-84 (77x) 5 TR 3.0-2 115 TR 3.3-39 (57viii) 28 TR 3.3-85 (77xi) 5 TR 3.0-3 92 TR 3.3-40 (60i) 62 TR 3.3-86 (77xii) 77 TR 3.0-4 115 TR 3.3-41 (60ii) 62 TR 3.3-87 (77xiii) 5 TR 3.1-1 (10i) 5 TR 3.3-42 (6li) 62 TR 3.3-88 86 TR 3.1-2 (17i) 128 TR 3.3-43 (61ii) 98 TR 3.3-89 90 TR 3.1-3 (17ii) 128 TR 3.3-44 (65i) 9 TR 3.3-90 (40i) 103 TR 3.1-4 (25i) 5 TR 3.3-45 (67i) 72 TR 3.4-1 (4i) 5 TR 3.2-1 (6i) 74 TR 3.3-46 (67ii) 75 TR 3.4-2 (5i) 48 TR 3.3-1 (6i) 127 TR 3.3-47 (67iii) 75 TR 3.4-3 (5ii) 86 TR 3.3-2 (9i) 48 TR 3.3-48 (71i) 85 TR'3.4-4 (l1i) 5 TR 3.3-3 (9ii) 142 TR 3.3-49 (7lii) 91 TR 3.4-5 (13i) 5 TR 3.3-4 (9iii) 78 TR 3.3-50 (71iii) 128 TR 3.4-6 (l6i) 127 TR 3.3-5 (lSi) 5 TR 3.3-51 (71iv) 38 TR 3.4-7 (16ii) 107 TR 3.3-6 (15ii) 5 TR 3.3-52 (71v) 38 TR 3.4-8 (16iii) 128 TR 3.3-7 (17i) 5 TR 3.3-53 (71vi) 77 TR 3.4-9 (19i) 128 TR 3.3-8 (17ii) 18 TR 3.3-54 (71vii) 128 TR 3.4-10 (32i) 101 TR 3.3-9 (17iii) 128 TR 3.3-55 (71viii) 5 TR 3.4-11 (32ii) 71 TR 3.3-10 (18i) 61 TR 3.3-56 (71ix) 79 TR 3.4-12 (32iii) 5 TR 3.3-11 (18ii) 86 TR 3.3-57 (71x) 5 TR 3.4-13 (33i) 5 TR 3.3-12 (24i) 5 TR 3.3-58 (71xi) 40 TR 3.4-14 (33ii) 5 TR 3.3-13 (24ii) 109 TR 3.3-59 (71xii) 5 TR 3.4-15 (33iii) 39 TR 3.3-14 (24iii) 109 TR 3.3-60 (71xiii) 40 TR 3.4-16 (33iv) 5 TR 3.3-15 (24iv) 109 TR 3.3-61 (71xiv) 40 TR 3.4-17 (33v) 5 TR 3.3-16 (28i) 127 TR 3.3-62 (71xv) 106 TR 3.5-1 (5i) 5 TR 3.3-17 (3li) 72 TR 3.3-63 (71xvi) 128 TR 3.5-2 (5ii) 5 TR 3.3-18 (37i) 5 TR 3.3-64 (71xvii) 119 TR 3.5-3 (12i) 77 TR 3.3-19 (43i) 9 TR 3.3-65 (71xviii) 67 TR 3.5-4 (12ii) 128 TR 3.3-20 (43ii) 9 TR 3.3-66 (71xix) 122 TR 3.6-1 (2i) 11 TR 3.3-21 (43iii) 9 TR 3.3-67 (71xx) 51 TR 3.6-2 (2ii) 144 TR 3.3-22 (43iv) 9 TR 3.3-68 (71xxi) 51 TR 3.6-3 (8i) 73 TR 3.3-23 (43v) 9 TR 3.3-69 (71xxii) 128 TR 3.6-3a (8ii) 143 TR 3.3-24 (43vi) 77 TR 3.3-70 (71xxiii) 128 TR 3.6-4 (8iii) 73 TR 3.3-25 (43vii) 128 TR 3.3-71 (71xxiv) 90 TR 3.6-5 (20i) 11 TR 3.3-26 (47i) 9 TR 3.3-72 (71xxv) 26 TR 3.6-6 (20ii) 77 TR 3.3-27 (52i) 116 TR 3.3-73 (71xxvi) 5 RIVER BEND TR-a Revision 144

Primary Containment -, Operating TR 3.6.1.1 TABLE 3.6.1.1-1 LEAKAGE PATHS

1. SECONDARY CONTAINMENT BYPASS LEAKAGE PATHS TO THE FUEL BUILDING PENETRATION VALVE NO. VALVE NO.

Containment air lock 1JRB*DRA2 KJB-Z26 SFC-MOVl19 SFC-V101 KJB-Z2.7 SFC,..,MOV12.2 SFC-MOV120 SFC-V350 KJB-Z2.8 SFC:...MOV121 SFC-MOV139 KJB-Z29 C11-MOVF083 C11-VF122 F42-GOO1. F42-MOVF003

2. DELETED i \

RIVER BEND TR 3.6-2 Revision 144 (2ii)

Enclosure 2 RBG-47775 Technical Specifications Bases Revision Pages

TECHNICAL SPECIFICATIONS BASES LIST OF EFFECTIVE PAGES PAGE REV PAGE REV PAGE REV PAGE REV NUMBER NUMBER NUMBER NUMBER B 2.0-1 0 B3.1-21 0 B 3.3-1 0 B 3.3-3ge 101 B 2.0-2 159 B 3.1-22 5-2 B 3.3-2 6-7 B 3.3-39f 4-8 B 2.0-3 162 B3.1-23 0 B 3.3-3 0 B 3.3-399 4-8 B 2.0-4 6-15 B 3.1-24 139 B 3.3-4 0 B 3.3-39h 4-8 B 2.0-5 115 B 3.1-25 107 B 3.3-5 0 B 3.3-40 0 B 2.0-6 115 B 3.1-26 139 B 3.3-6 0 B 3.3-41 6-13 B 2.0-7 0 B 3.1-27 0 B 3.3-7 6-4 B 3.3-42 6-6 B 2.0-8 115 B 3.1-28 0 B 3.3-8 4-8 B 3.3-43 6-13 B 2.0-9 115 B 3.1-29 6-14 B 3.3-8a 4-8 B 3.3-44 0 B 3.0-1 150 B 3.1-30 6-14 B 3.3-8b 4-8 B 3.3-45 0 B 3.0-2 0 B3.1-31 6-14 B 3.3-9 4-8 B 3.3-46 0 B 3.0-3 0 B 3.1-32 0 B 3.3-10 4-8 B 3.3-47 143 B 3.0-4 0 B 3.1-33 6-13 B 3.3-11 1 B 3.3-48 6-13 B 3.0-5 133 B 3.1-34 6-13 B 3.3-12 0 B 3.3-49 1 B 3.0-5a 158 B 3.1-35 6-13 B 3.3-13 6-4 B 3.3-50 0 B 3.0-5b 133 B 3.1-36 0 B 3.3-14 0 B 3.3-51 1 B 3.0-6 133 B3.1-37 143 B 3.3-15 0 B 3.3-52 116 B 3.0-7 0 B 3.1-38 143 B 3.3-16 0 B 3.3-53 6-2 B 3.0-8 142 B 3.1-39 0 B 3.3-17 2-7 B 3.3-54 122 B 3.0-8a 142 B 3.1-40 0 B 3.3-18 1 B 3.3-55 133 B 3.0-9 150 B3.1-41 5-6 B 3.3-19 1 B 3.3-56 133 B 3.0-9a 158 B 3.1-42 1 B 3.3-20 1 B 3.3-57 0 B 3.9-9b 150 B 3.1-43 143 B 3.3-21 1 B 3.3-58 0 B 3.0-10 0 B 3.1-44 143 B 3.3-22 1 B 3.3-59 143 B 3.0-11 0 B 3.1-45 115 B 3.3-23 1 B 3.3-60 0 B 3.0-12 108 B 3.1-46 118 B 3.3-24 1 B 3.3-61 147 B 3.0-13 161 B 3.1-47 118 B 3.3-25 6-4 B 3.3-62 133 B 3.0-13a 158 B 3.1-48 0 B 3.3-25a 4-8 B 3.3-63 0 B 3.0-14 133 B 3.1-49 143 B 3.3-26 4-8 B 3.3-64 143 B 3.0-15 133 B 3.2-1 0 B 3.3-27 6-15 B 3.3-65 0 B 3.1-1 0 B 3.2-2 6-4 B 3.3-28 143 B 3.3-66 124 B 3.1-2 0 B 3.2-3 6-4 B 3.3-29 143 B 3.3-67 124 B 3.1-3 0 B 3.2-4 3-7 B 3.3-30 143 B 3.3-68 1 B 3.1-4 0 B 3.2-5 0 B 3.3-31 143 B 3.3-69 1 B 3.1-5 0 B 3.2-6 6-15 B 3.3-31a 4-8 B 3.3-70 124 B 3.1-6 0 B 3.2-7 6-4 B 3.3-32 0 B 3.3-71 124 B 3.1-7 3-10 B 3.2-8 6-15 B 3.3-33 0 B 3.3-72 1 B 3.1-8 3-10 B 3.2-9 0 B 3.3-34 0 B 3.3-73 143 B 3.1-9 3-10 B3.2-10 6-4 B 3.3-35 0 B 3.3-74 143 B 3.1-10 3-10 B 3.2-11 6-4 B 3.3-36 136 B 3.3-75 2-1 B 3.1-11 3-10 B 3.2-12 4-8 B 3.3-37 0 B 3.3-76 0 B3.1-12 0 B 3.2-13 4-8 B 3.3-38 0 B 3.3-77 106 B 3.1-13 0 B 3.2-14 4-8 B 3.3-39 143 B 3.3-78 0 B 3.1-14 0 B3.2-15 4-8 B 3.3-39a 4-8 B 3.3-79 0 B 3.1-15 136 B 3.2-16 4-8 B 3.3-39b 162 B 3.1-16 0 B3.2-17 4-8 B 3.3-39c 4-8 B 3.1-17 6-13 B 3.2-18 4-8 B 3.3-39d 4-8 B 3.1-18 136 B 3.1-19 1 B 3.1-20 0 RIVER BEND TSB-a Revision No. 162

TECHNICAL SPECIFICATIONS BASES LIST OF EFFECTIVE PAGES PAGE REV PAGE REV PAGE REV PAGE REV NUMBER NUMBER NUMBER NUMBER B 3.6-90 6-5 B 3.6-130 2-4 B 3.7-28 143 B 3.8-35 0 B 3.6-91 115 B 3.6-131 2-4 B 3.7-29 115 B 3.8-36 0 B 3.6-92 6-5 B 3.6-132 3-4 B 3.7-30 0 B 3.8-37 115 B 3.6-93 115 B 3.6-133 3-4 B 3.7-31 115 B 3.8-38 110 B 3.6-94 143 B 3.6-134 2-8 B 3.8-1 0 B 3.8-39 102 B 3.6-95 6-5 B 3.6-135 143 B 3.8-2 5-3 B 3.8-40 102 B 3.6-96 159 B 3.6-136 6-2 B 3.8-3 0 B 3.8-41 3-2 B 3.6-97 159 B 3.6-137 2-8 B 3.8-4 153 B 3.8-42 0 B 3.6-98 161 B 3.6-138 2-8 B 3.8-4a 154 B 3.8-43 0 B 3.6-98a 161 B 3.6-139 2-8 B 3.8-5 154 B 3.8-44 0 B 3.6-99 159 B 3.6-140 2-8 B 3.8-6 154 B 3.8-45 155 B 3.6-100 161 B 3.6-141 2-8 B 3.8-7 154 B 3.8-46 0 B 3.6-101 121 B 3.6-142 2-8 B 3.8-8 154 B 3.8-47 0 B 3.6-102 121 B 3.7-1 110 B 3.8-8a 154 B 3.8-48 3-2 B 3.6-103 121 B 3.7-2 110 B 3.8-9 154 B 3.8-49 134 B3.6-104 6-5 B 3.7-3 110 B 3.8-10 154 B 3.8-50 0 B 3.6-105 110 B 3.7-4 1 B 3.8-11 154 B 3.8-51 125 B 3.6-106 0 B 3.7-5 1 B 3.8-12 154 B 3.8-51a 125 B 3.6-107 6-5 B 3.7-6 161 B3.8-13 161 B 3.8-52 125 B3.6-108 6-5 B 3.7-6a 161 B 3.8-13a 161 B 3.8-52a 125 B 3.6-109 6-5 B 3.7-7 3-1 B 3.8-14 127 B 3.8-52b 148 B3.6-110 6-5 B 3.7-8 143 B 3.8-15 162 B 3.8-53 161 B3.6-111 6-5 B 3.7-9 161 B 3.8-16 151 B 3.8-53a 161 B 3.6-112 159 B 3.7-10 159 B 3.8-17 102 B 3.8-54 161 B 3.6-113 110 B 3.7-11 159 B 3.8-18 153 B 3.8-55 143 B 3.6-114 6-5 B 3.7-12 132 B 3.8-18a 153 B 3.8-56 143 B 3.6-115 159 B 3.7-12a 161 B 3.8-19 157 B 3.8-57 120 B3.6-116 143 B 3.7-13 161 B 3.8-20 143 B 3.8-58 161 B3.6-117 0 B 3.7-13a 161 B 3.8-21 143 B 3.8-59 110 B3.6-118 0 B 3.7-14 159 B 3.8-22 113 B 3.8-60 110 B3.6-119 143 B 3.7-15 143 B 3.8-23 143 B 3.8-61 115 B 3.6-120 135 B 3.7-16 161 B 3.8-24 143 B 3.8-62 0 B3.6-121 119 B 3.7-17 157 B 3.8-25 162 B 3.8-63 0 B 3.6-122 2-4 B 3.7-18 110 B 3.8-26 151 B 3.8-64 0 B 3.6-123 2-4 B 3.7-19 161 B 3.8-27 143 B 3.8-65 0 B 3.6-124 2-4 B 3.7-19a 161 B 3.8-28 143 B 3.8-66 1 B 3.6-125 2-4 B 3.7-20 115 B 3.8-29 143 B 3.8-67 4-5 B 3.6-126 2-4 B 3.7-21 161 B 3.8-30 143 B 3.8-68 4-5 B 3.6-127 2-4 B 3.7-22 0 B 3.8-31 102 B 3.8-69 1 B 3.6-128 143 B 3.7-23 161 B 3.8-32 161 B 3.6-129 3-4 B 3.7-24 161 B 3.8-33 3-1 B 3.7-25 137 B 3.8-34 110 B 3.7-26 137 B 3.7-27 143 RIVER BEND TSB-d Revision No. 162

Reactor Core SLs B 2.1.1 BASES APPLICABLE 2.1.1.1 Fuel Cladding Integrity SAFETY ANALYSES (continued) 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 < 685 psig is conservative.

Because of the design thermal hydraulic compatibility of the reload fuel designs with the cycle 10 fuel, this justification and the associated low pressure and low flow limits remain applicable for future cycles of cores containing these fuel designs.

2.1.1.2 MCPR The MCPR SL ensures sufficient conservatism in the operating limit MCPR limit that, in the event of an AOO from the limiting condition of operation, at least 99.9% of the fuel rods in the core would be expected to avoid boiling transition. The margin between calculated boiling transition

=

(Le., MCPR 1.00) and the MCPR SL is based on a detailed statistical procedure that considers the uncertainties in monitoring the core operating state. One specific uncertainty included in the SL is the uncertainty inherent in the critical power correlation. Reference 6 describes the methodology used in determining the MCPR SL.

The calculated MCPR safety limit is reported to the customary three significant digits (Le., X.XX); the MCPR operating limit is developed based on the calculated MCPR safety limit to ensure that at least 99.9%

of the fuel rods in the core are expected to avoid boiling transition.

The fuel vendor's critical power correlations are based on a significant body of practical test data, providing a high degree of assurance that the critical power, as evaluated by the correlation, is within a small percentage of the actual critical power being estimated. As long as the core pressure and flow are within the range of validity of the correlations, the assumed reactor conditions used in defining the SL introduce conservatism into the limit because bounding high radial power factors and bounding flat local peaking distributions are used to estimate the number of rods in boiling transition. These conservatisms and the inherent accuracy of the fuel vendor's correlation provide a reasonable degree of assurance that 99.9% of the rods in the core would not be susceptible to transition boiling during (continued)

RIVER BEND B 2.0-3 Revision No. 162

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.2 and SR 3.8.1.7 (continued)

REQUIREMENTS SR 3.8.1.7 requires that, at a 184-day Frequency, the DG starts from standby conditions and achieves the required voltage and frequency within 10 seconds for DG 1A and DG 1B and 13 seconds for DG 1C. The start requirements for each DG support the assumptions in the design basis LOCA analysis (Ref. 5). The start requirements may not be applicable to 3.8.1.2 (see Note 3 of SR 3.8.1.2), when a modified start as described above is used. If a modified start is not used, the start requirements of SR 3.8.1.7 apply. Since SR 3.8.1.7 does require a 10 second start for DG 1A and DG 1Band 13 seconds for DG 1C, it is more restrictive than SR 3.8.1.2, and it may be performed in lieu of SR 3.8.1.2.

This is the intent of Note 1 of SR 3.8.1.2. Similarly, the performance of SR 3.8.1.12 or SR 3.8.1.19 also satisfies the requirements of SR 3.8.1.2 and SR 3.8.1.7.

In addition to the SR requirements, the time for the DG to reach steady state operation, unless the modified DG start method is employed, is periodically monitored and the trend evaluated to identify degradation of governor and voltage regulator performance.

The normal 31 day Frequency for SR 3.8.1.2 is consistent with the industry guidelines for assessment of diesel generator performance (Refs. 14 and 15). The 184 day Frequency for SR 3.8.1.7 is a reduction in cold testing consistent with Generic Letter 84-15 (Ref. 7). These Frequencies provide adequate assurance of DG OPERABILITY, while minimizing degradation resulting from testing.

SR 3.8.1.3 This Surveillance demonstrates that the DGs are capable of synchronizing and accepting the surveillance test. The minimum run time of 60 minutes is required to stabilize engine temperatures, while minimizing the time that the DG is connected to the offsite source.

Although no power factor requirements are established by this SR, the DG is normally operated at a power factor between 0.8 lagging and 1.0.

The 0.8 value is the design rating of the machine, while 1.0 is an operational limitation to ensure circulating (continued)

RIVER BEND B 3.8-15 Revision No. 162

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.14 (continued)

REQUIREMENTS equivalent to the continuous rating of the DG, and 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months of which is at a load equivalent to 110% of the continuous duty rating of the DG for Division III. An exception to the loading requirements is made for DG 1A and DG 1B. DG 1A and DG 1B are operated for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months at a load greater than or equal to the maximum expected post accident load. Load carrying capability testing of the Transamerica Delavallnc. (TOI) diesel generators (DG 1A and DG 1B) has been limited to a load less than that which corresponds to 201 psig brake mean effective pressure (BMEP).

Therefore, full load testing is performed at a load ~ 3050 kW but < 3130 kW. The DG starts for this Surveillance can be performed either from standby or hot conditions. The provisions for prelube and warmup, discussed in SR 3.8.1.2, and for gradual loading, discussed in SR 3.8.1.3, are applicable to this SR.

In order to ensure that the DG is tested under load conditions that are as close to design conditions as possible, testing must be performed using a power factor s:; 0.9. This power factor is chosen to be representative of the actual design basis inductive loading that the DG could experience.

The 24 month Frequency takes into consideration plant conditions required to perform the Surveillance; and is intended to be consistent with expected fuel cycle lengths.

This Surveillance is modified by two Notes. Note 1 states that momentary transients do not invalidate this test. The lower limit of the load band ensures the generator is sufficiently loaded during the test and the upper limit of the load band is to avoid an overload of the diesel generator during the routine test. The upper and lower limits provide a reasonable band to operate the DG in for the specified run time while achieving the intent of a full-load. The Note recognizes that there are external grid conditions that can cause a shift in load sharing with the DG and allows the operator time to recognize and adjust load back into the band without invalidating the performance of the surveillance. It also allows for momentary transients where the DG governor system acts to bring the load back into the load band. Momentary DG load "spikes" which are beyond the ability of the operator to monitor and control with normal control room instrumentation, and which the governor acted to maintain proper DG load band do not invalidate the test and the DG can be considered to have met the intent of operating "at full rated load" for the specified duration. Similarly, momentary power factor transients above the limit do not invalidate the test. The reason for Note 2 is that credit may be taken for unplanned events (continued)

RIVER BEND B 3.8-25 Revision No. 162

PBDS B 3.3.1.3 BASES BACKGROUND by an indicating light on the card front panel. A manually initiated internal (continued) test sequence can be actuated via a recessed push button. This internal test consists of simulating alarm and inoperable conditions to verify card OPERABILITY. Descriptions of the PBDS are provided in References 1 and 2.

Actuation of the PBDS Hi-Hi DR Alarm is not postulated to occur due to neutronic/thermal hydraulic instability outside the Restricted Region and the Monitored Region. Periodic perturbations can be introduced into the thermal hydraulic behavior of the reactor core from external sources such as recirculation system components and the pressure and feedwater control systems. These perturbations can potentially drive the neutron flux to oscillate within a frequency range expected for neutronic/thermal hydraulic instability. The presence of such oscillations would be recognized by the period based algorithm of the PBDS and potentially result in a Hi-Hi DR Alarm. Actuation of the PBDS Hi-Hi DR Alarm outside the Restricted Region and the Monitored Region would indicate the presence of a source external to the reactor core and are not indications of neutronic/thermal hydraulic instability.

APPLICABLE Analysis, as described in Section 4 of Reference 1, confirms that AOOs SAFETY ANALYSES initiated from outside the Restricted Region without stability control and from within the Restricted Region with stability control are not expected to result in neutronic/thermal hydraulic instability. The stability control applied in the Restricted Region (refer to LCO 3.2.4, "Fraction of Core Boiling Boundary (FCBB)") is established to prevent neutronic/thermal hydraulic instability during operation in the Restricted Region. Operation in the Monitored Region is only susceptible to instability under hypothetical operating conditions beyond those analyzed in Reference 1.

The types of transients specifically evaluated are loss of flow and coolant temperature decrease, which are limiting for the onset of instability.

The initial conditions assumed in the analysis are reasonably conservative and the immediate post-event reactor conditions are significantly stable. However, these assumed initial conditions do not bound each individual parameter which impacts stability performance (Ref.1). The PBDS instrumentation provides the (continued)

RIVER BEND B 3.3-39b Revision No. 162

TECHNICAL SPECIFICATIONS BASES LIST OF EFFECTIVE PAGES Ii PAGE NUMBER I REV PAGE NUMBER I REV PAGE NUMBER I REV PAGE NUMBER I REV I

I B 3.4-18 0 B 3.4-57 0 B 3.6-9 2-3 B 3.6-50 6-13 B3.4-19 109 B 3.4-58 0 B 3.6-10 2-3 B 3.6*51 110 B 3.4-20 143 B 3.4-59 0 B3.6-11 2-3 B 3.6-52 110 B 3.4-21 B 3.4-21 a 140 140 B 3.4-60 B 3.4-61 0

6-13 B 3.6-12 B 3.6-13 128 6-10 B 3.6-53 B 3.6*54 0

0 I B 3.4-22 0 B 3.4-62 6-14 B 3.6-14 143 B 3.6-55 0 B 3.4-23 0 B 3.4-63 6-14 B3.6-15 3-4 B 3.6-56 0 B 3.4-24 0 B 3.5-1 0 B 3.6-16 144 B 3.6-57 0 B 3.4-25 0 B 3.5-2 0 B 3.6-17 128 B 3.6-58 0 B 3.4-26 0 B 3.5-3 6-14 B 3.6-18 3-4 B 3.6-59 3-4 B 3.4-27 0 B 3.5-4 3-7 B 3.6-19 3*4 B 3.6-60 0 B 3.4-28 140 B 3.5-5 163 B 3.6-20 128 B 3.6-61 0 I B 3.4-29 0 B 3.5-6 133 B 3.6-21 129 B 3.6-62 0 B 3.4-30 0 B 3.5-7 161 B 3.6-22 110 B 3.6-63 163 I B 3.4-31 140 B 3.5-7a 161 B 3.6-23 0 B 3.6-64 161 B 3.4-32 149 B 3.5-8 161 B 3.6-24 6-11 B 3.6-64a 163 B 3.4-33 149 B 3.5-8a 161 B 3.6-24a 6-11 B 3.6*64b 163 B 3.4-34 149 B 3.5*9 163 B 3.6-25 129 B 3.6-65 163 B 3.4-34a 149 B 3.5-9a 163 B 3.6-26 143 B 3.6-66 122 B 3.4-35 133 B 3.5-10 163 B 3.6-27 121 B 3.6-67 122 B 3.4-36 149 B 3.5-11 143 B 3.6-28 110 B 3.6-68 122 B 3.4-36a 149 B 3.5-12 143 B 3.6-29 2-1 B 3.6*69 122 B 3.4*37 149 B 3.5-13 140 B 3.6-30 0 B 3.6-70 122 B 3.4-38 149 B3.5-13a 143 B 3.6-31 0 B 3.6-71 122 B 3.4-39 110 B 3.5-14 161 B 3.6-32 0 B 3.6-72 0 B 3.4-40 110 B 3.5-15 163 B 3.6-33 0 B 3.6-73 0 I B 3.4-41 133 B 3.5-16 a B 3.6-34 a B 3.6-74 0 B 3.4-42 110 B 3.5-17 0 B 3.6-35 161 B 3.6-75 133 B 3.4-43 0 B 3.5-18 0 B 3.6-36 161 B 3.6-76 143 B 3.4-44 163 B 3.5-19 163 B 3.6-36a 161 B 3.6-77 143 I B3.4-45 133 B 3.5-20 6-14 B 3.6-37 109 B 3.6-78 122 B 3.4-46 0 B 3.5-21 163 B 3.6-38 161 B 3.6-79 0 B 3.4-47 163 B 3.5-22 133 B 3.6-39 144 B 3.6-80 133 B 3.4-47a 163 B 3.5-23 163 B 3.6-40 0 B 3.6-81 2-8 B 3.4-48 0 B 3.5-23a 163 B 3.6-41 161 B 3.6-82 143 B 3.4-49 163 B 3.5-24 143 B 3.6-41a 161 B 3.6-83 121 B 3.4-50 0 B 3.5-25 143 B 3.6-42 161 B 3.6-84 6-5 B 3.4-51 0 B 3.6-1 0 B 3.6-43 3-9 B 3.6-85 161 B 3.4-52 163 B 3.6-2 156 B 3.6-44 3-9 B 3.6-85a I

161 B 3.4-52a 163 B 3.6-2a 156 B 3.6-45 3-9 B 3.6-86 161 B 3.4-53 6-4 B 3.6-3 2-1 B 3.6-46 3-9 B 3.6-87 161 B 3.4-54 6-13 B 3.6-4 156 B 3.6-47 1 B 3.6-88 6-5 B 3.4-55 6-4 B 3.6-5 0 B 3.6-48 161 B 3.6-89 6-5 B 3.4-56 0 B 3.6'{) 110 B 3.6-48a 161 B 3.6-7 110 B 3.6-49 161 B 3.6-8 2-3 RIVER BEND TSB-c Revision No. 163

TECHNICAL SPECIFICATIONS BASES LIST OF EFFECTIVE PAGES PAGE REV PAGE PAGE REV PAGE REV NUMBER NUMBER NUMBER NUMBER B 3,8-70 111 B 3.9-18 0 83,10-23 0 83.8-71 111 83.9-19 115 83.10-24 a 83.8-72 161 83.9-20 119 B 3.10-25 a 83.8-72a 161 B 3.9-21 115 B 3.10-26 0 B 3.8-73 161 B 3.9-22 115 B 3.10-27 0 83.8-74 110 83.9-23 119 B 3,10-28 0 83,8-75 115 B 3,9-24 115 83.10-29 a 83.8-76 110 B 3.9-25 a B 3.10-30 0 83.8-77 a B 3.9-26 163 B 3.10-31 0 83.8-78 0 B 3.9-27 4-2 83.10-32 0 83.8-79 1 83.9-28 4-2 B 3.10-33 0 83.8-80 0 83.9-28a 163 B 3.10-34 0 B 3.8-81 0 83.9-28b 163 83.10-35 0 83.8-82 0 83.9*29 163 83.10-36 0 B 3,8-83 0 83,9-30 0 83.10-37 0 B 3,8-84 0 83.9-31 4-2 83.10-38 6-14 B 3.8-85 161 83.9-32 4-2 83.8-85a 161 83.9-32a 163 B 3.8-86 161 B 3,9*32b 163 83.8-87 161 B 3.10-1 146 83.8-88 160 B 3.10-2 146 B 3.8-89 110 B 3.10-3 146 B 3.8-90 115 B 3.10-4 a B 3.8-91 115 B 3.10-5 0 B 3.8-92 0 B 3.10-6 0 83.9-1 0 B3.10-7 0 B 3.9-2 0 B 3.10-8 0 B 3.9-3 4-5 B 3.10-9 0 B 3.9-4 119 83.10-10 0 B 3.9-5 0 B 3.10-11 0 B 3.9-6 0 B3.10-12 0 8 3.9-7 0 B3.10-13 0 B 3.9*8 0 B 3.10-14 0 83.9-9 0 B3.10-15 0 B 3.9-10 103 B3.10-16 0 B3.9-11 0 83.10-17 0 B 3.9-12 0 B3.10-18 0 B 3.9-13 0 B 3.10-19 0 B 3.9-14 0 B 3.10-20 0 B 3.9*15 0 B 3.10-21 0 B 3.9-16 0 B 3.10-22 0 B 3.9-17 6-14 RIVER BEND TSB-e Revision No. 163

RHR Shutdown Cooling System - Hot Shutdown B 3.4.9 BASES LCO aligned (remote or local) in the shutdown cooling mode for removal of (continued) decay heat. In MODE 3, one RHR shutdown cooling subsystem can provide the required cooling, but two subsystems are required to be OPERABLE to provide redundancy. Operation of one subsystem can maintain or reduce the reactor coolant temperature as required.

However, to ensure adequate core flow to allow for accurate average reactor coolant temperature monitoring. nearly continuous operation is required. Management of gas voids is important to RHR Shutdown Cooling System OPERABILITY, Note 1 permits both RHR shutdown cooling subsystems and recirculation pumps to be shut down for a period of 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months in an 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months period.

Note 2 allows one RHR shutdown cooling subsystem to be inoperable for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for performance of surveHlance tests, These tests may be on the affected RHR System or on some other plant system or component that necessitates plaCing the RHR System in an inoperable status during the performance. This is permitted because the core heat generation can be low enough and the heatup rate slow enough to allow some changes to the RHR subsystems or other operations requiring RHR flow interruption and loss of redundancy.

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

In MODE 3 with reactor steam dome pressure below the RHR cut in permissive pressure (Le., the actual pressure at which the interfock resets) the RHR System may be operated in the shutdown cooling mode to remove decay heat to reduce or maintain coolant temperature.

(continued)

RIVER BEND B 3.4-44 Revision No. 163

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

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

SURVEILLANCE SR 3.4.9.1 REQUIREMENTS This Surveillance verifies that one RHR shutdown cooling subsystem or recirculation pump is in operation and Circulating reactor coolant. The required flow rate is determined by the flow rate necessary to provide sufficient decay heat removal capability. The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is sufficient in view of other visual and audible indications available to the operator for monitoring the RHR subsystem in the control room.

This Surveillance is modified by a Note allowing sufficient time to align the RHR System for shutdown cooling operation after clearing the pressure interlock that isolates the system, or for placing a recirculation pump in operation. The Note takes exception to the requirements of the Surveillance being met (Le., forced coolant circulation is not required for this initial 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months period), which also allows entry into the Applicability of this Specification in accordance with SR 3.0.4 since the Surveillance will not be "not met" at the time of entry into the Applicability.

SR3A9.2 RHR Shutdown Cooling System piping and components have the potential to develop voids and pockets of entrained gases. Preventing and managing gas intrusion and accumulation is necessary for proper operation of the RHR shutdown cooling subsystems and may also prevent water hammer, pump cavitation, and pumping of noncondensible gas into the reactor vessel.

Selection of RHR Shutdown Cooling System locations susceptible to gas accumUlation is based on a review of system design information, including piping and instrumentation drawings, isometriC drawings, plan and elevation drawings, and calculations. The design review is supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance or restoration.

(continued)

RIVER BEND B 3.4-47 Revision No. 163

RHR Shutdown Cooling System - Hot Shutdown B 3.4.9 BASES SURVEILLANCE SR 3.4.9.2 (continued}

REQUIREMENTS Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions.

The RHR Shutdown Cooling System is OPERABLE when it is sufficiently filled with water. Acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location (or the volume of accumulated gas at one or more susceptible location exceeds an acceptance criteria for gas volume at the suction or discharge of a pump), the Surveillance is not met. If it is determined by subsequent evaluation that the RHR Shutdown Cooling System is not rendered inoperable by the accumulated gas (Le., the system is sufficiently filled with water), the Surveillance may be declared met.

Accumulated gas should be eliminated or brought within the acceptance criteria limits.

RHR Shutdown Cooling System locations susceptible to gas accumulation are monitored and, if gas is found, the gas volume is compared to the acceptance criteria for the location. Susceptible locations in the same system flow path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representative sub-set of susceptible locations. Monitoring may not be practical for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or personnel safety. For these locations alternative methods (e.g .* operating parameters, remote monitoring) may be used to monitor the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance Interval.

This SR is modified by a Note that states the SR is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months reactor steam dome pressure is < the RHR cut in permissive pressure. After a rapid shutdown, there may be insufficient time to verify all susceptible locations prior to entering the Applicability.

The 31 day Frequency takes into consideration the gradual nature of gas accumulation in the RHR Shutdown Coofing System piping and the procedural controls governing system operation.

REFERENCES None, RIVER BEND B 3.4-47a Revision No. 163

RHR Shutdown Cooling System-Cold Shutdown B 3.4.10 BASES LCO aligned (remote or local) in the shutdown cooling mode for removal of (continued) decay heat. In MODE 4, one RHR shutdown cooling subsystem can provide the required cooling. but two subsystems are required to be OPERABLE to provide redundancy. Operation of one subsystem can maintain and reduce the reactor coolant temperature as required.

However. to ensure adequate core flow to allow for accurate average reactor coolant temperature monitoring, nearly continuous operation is required. Management of gas voids is important to RHR Shutdown Cooling System OPERABILITY.

Note 1 permits both RHR shutdown cooling subsystems and recirculation pumps to be shut down for a period of 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months in an 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months period.

Note 2 allows one RHR shutdown cooling subsystem to be inoperable for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for performance of surveillance tests. These tests may be on the affected RHR System or on some other plant system or component that necessitates placing the RHR System in an inoperable status during the performance. This is permitted because the core heat generation can be low enough and the heatup rate slow enough to allow some changes to the RHR subsystems or other operations requiring RHR flow interruption and loss of redundancy.

Note 3 permits both RHR shutdown cooling subsystems and recirculation pumps to be shut down during performance of inservice leak testing and during hydrostatic testing. This is permitted because RCS pressures and temperatures are being closely monitored as required by LCO 3.4.11.

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

(continued)

RIVER BEND B 3.4-49 Revision No. 163

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

REQUIREMENTS determined by the flow rate necessary to provide sufficient decay heat removal capability. The Fre<1uency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is sufficient in view of other visual and audible indications available to the operator for monitoring the RHR subsystem in the control room.

SR 3.4.10.2 RHR Shutdown Cooling System piping and components have the potential to develop voids and pockets of entrained gases. Preventing and managing gas intrusion and accumulation is necessary for proper operation of the RHR shutdown cooling subsystems and may also prevent water hammer, pump cavitation, and pumping of noncondensible gas into the reactor vessel.

Selection of RHR Shutdown Cooling System locations susceptible to gas accumulation is based on a review of system design information, including piping and instrumentation drawings, isometric drawings, plan and elevation drawings, and calculations. The design review is supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance or restoration.

Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions.

The RHR Shutdown Cooling System is OPERABLE when it is sufficiently filled with water. Acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location (or the volume of accumulated gas at one or more susceptible location exceeds an acceptance criteria for gas volume at the suction or discharge of a pump), the Surveillance is not met. If it is determined by subsequent evaluation that the RHR Shutdown Cooling System is not rendered inoperable by the accumulated gas (Le., the system is sufficiently filled with water), the Surveillance may be declared met.

Accumulated gas should be eliminated or brought within the acceptance criteria limits.

RHR Shutdown Cooling System locations susceptible to gas accumulation are monitored and, if gas is found, the gas volume is compared to the acceptance criteria for the location. Susceptible locations in the same system flow path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representative sub-set of susceptible locations. Monitoring may not be practical for locations (continued)

RIVER BEND B 3.4-52 Revision No. 163

RHR Shutdown Cooling System-Cold Shutdown B 3.4.10 BASES SURVEILLANCE SR 3.4.10.2 (continued)

REQUIREMENTS that are inaccessible due to radiological or environmental conditions. the plant configuration. or personnel safety. For these locations alternative methods (e.g., operating parameters. remote monitoring) may be used to monitor the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABiliTY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABiliTY during the Surveillance interval.

The 31 day Frequency takes into consideration the gradual nature of gas accumulation in the RHR Shutdown Cooling System piping and the procedural controls governing system operation.

REFERENCES None.

RIVER BEND B 3.4-52a Revision No. 1

EGGS-Operating B 3.5.1 BASES (continued)

LCO Each EGGS injection/spray subsystem and seven ADS valves are required to be OPERABLE. The EGCS injection/spray subsystems are the three LPGI subsystems, the LPGS System, and the HPGS System.

The EGGS injection/spray subsystems are further subdivided into the following groups. Management of gas voids is important to EGGS injection/spray subsystem OPERABILITY.

a) The low pressure EGGS injection/spray subsystems are the LPCS System and the three LPGI subsystems; b} The EGGS injection subsystems are the three LPGI subsystems; and c) The EGGS spray subsystems are the HPGS System and the LPGS System.

With less than the required number of EGGS subsystems OPERABLE during a limiting design basis LOGA concurrent with the worst case single failure, the limits specified in 10 GFR 50.46 (Ref. 10) could potentially be exceeded. All EGGS subsystems must therefore be OPERABLE to satisfy the single failure criterion required by 10 GFR 50.46 (Ref. 10).

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

APPLICABILITY All EGCS subsystems are required to be OPERABLE during MODES 1, 2, and 3 when there is considerable energy in the reactor core and core cooling would be required to prevent fuel damage in the event of a break in the primary system piping. In MODES 2 and 3, the ADS function is not required when pressure is s; 100 psig because the low pressure EGGS subsystems {LPGS and LPGI} are capable of providing flow into the RPV below this pressure. ECGS reqUirements for MODES 4 and 5 are specified in LCO 3.5.2, "ECGS-Shutdown."

(continued)

RIVER BEND B 3.5-5 Revision No. 163

ECCS-Operating B 3.5.1 BASES (continued)

SURVEILLANCE SR 3.5.1.1 REQUIREMENTS The ECCS injection/spray subsystem flow path piping and components have the potential to develop voids and pockets of entrained gases.

Preventing and managing gas intrusion and accumulation is necessary for proper operation of the ECCS injection/spray subsystems and may also prevent a water hammer, pump cavitation, and pumping of noncondensible gas into the reactor vessel.

Selection of ECCS injection/spray subsystem locations susceptible to gas accumulation is based on a review of system design information.

including piping and instrumentation drawings, isometric drawings, plan and elevation drawings, and calculations. The design review is supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance or restoration.

Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions.

The ECCS injection/spray subsystem is OPERABLE when it is sufficiently filled with water. Acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location (or the volume of accumulated gas at one or more susceptible location exceeds an acceptance criteria for gas volume at the suction or discharge of a pump), the Surveillance is not met. If it is determined by subsequent evaluation that the ECCS injection/spray subsystems are not rendered inoperable by the accumulated gas (Le., the system is sufficiently filled with water), the Surveillance may be declared met.

Accumulated gas should be eliminated or brought within the acceptance criteria limits.

ECCS injection/spray SUbsystem locations susceptible to gas accumulation are monitored and, if gas is found. the gas volume is compared to the acceptance criteria for the location. Susceptible locations in the &arne system flow path which are subject to the same (continued)

RIVER BEND B 3.5-9 Revision No. 163

EGGS-Operating B 3.5.1 BASES (continued) gas intrusion mechanisms may be verified by monitoring a representative sub-set of susceptible locations. Monitoring may be practical for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or personnel safety. For these locations alternative methods (e.g., operating parameters, remote monitoring) may be used to monitor the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval.

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

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

This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.

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

(continued)

RIVER BEND B 3.5-9a Revision No. 163

ECCS-Operatfng B 3.S.1 BASES SURVEILLANCE SR 3.S.1.2 (continued)

REQUIREMENTS This SR is modified by Note 1 that allows LPCI subsystems to be considered OPERABLE during alignment and operation for decay heat removal with reactor steam dome pressure less than the RHR cut in permissive pressure in MODE 3, if capable of being manually realigned (remote or local) to the LPCI mode and not otherwise inoperable. This allows operation in the RHR shutdown cooling mode during MODE 3 if necessary.

This SR is also modified by Note 2 which exempts system vent flow paths opened under administrative control. The administrative control should be procedurallzed and include stationing a dedicated individual at the system vent flow path who is in continuous communication with the operators in the control room. This individual will have a method to rapidly close the system vent flow path if directed.

SR 3.5.1.3 Verification every 31 days that ADS air accumulator supply pressure is 131 pslg assures adequate air pressure for reliable ADS operation. The accumulator on each ADS valve provides pneumatic pressure for valve actuation. The designed pneumatic supply pressure requirements for the accumulator are such that, following a failure of the pneumatic supply to the accumulator, at least two valve actuations can occur with the drywell at 70% of design pressure (Ref. 13), The ECCS safety analysis assumes only one actuation to achieve the depressurization required for operation of the low pressure ECCS. This minimum required pressure of 131 psig is provided by the nonsafety related air supply system (SW) with safety related backup from the penetration valve leakage control system (LSV),

post LOCA, at a system design pressure of 120 psig. The 31 day Frequency takes into consideration administrative control over operation of the SW and LSV Systems and alarms for low air pressure.

SR 3.S.1.4 The performance requirements of the ECCS pumps are determined through application of the 10 CFR SO, Appendix K. criteria (Ref. 8). This periodic Surveillance is performed (in accordance with the ASME OM Code requirements for the ECCS pumps) to verify that the ECCS pumps will develop the flow rates required by the respective analyses. The ECCS pump flow rates ensure that adequate core cooling is provided to satisfy the acceptance criteria of 10 CFR 50.46 (Ref. 10).

(continued)

RIVER BEND B 3.5-10 Revision No. 163

ECCS-Shutdown B3.5.2 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RC1C) SYSTEM B 3.5.2 ECCS-Shutdown BASES BACKGROUND A description of the High Pressure Core Spray (HPCS) System. Low Pressure Core Spray (LPCS) System, and low pressure coolant injection (LPCI) mode of the Residual Heat Removal (RHR) System is provided in the Bases for LCO 3.5.1, "ECCS-Operating."

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

The ECCS satisfy Criterion 3 of the NRC Policy Statement.

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

The ECCS injection/spray subsystems are defined as the three LPGI subsystems, the LPCS System, and the HPCS System. The LPCS System and each LPCI subsystem consist of one motor driven pump, piping, and valves to transfer water from the suppression pool to the RPV.

The HPCS System consists of one motor driven pump, piping, and valves to transfer water from the suppression pool or condensate storage tank (CST) to the RPV. Management of gas voids is important to ECGS injection/spray subsystem OPERABILITY.

One LPCI subsystem (A or B) may be aligned for decay heat removal in MODE 4 or 5 and considered OPERABLE for the ECCS function, if it can be manually realigned (remote or local) to the LPCI mode and is not otherwise inoperable. Because of low pressure and low temperature conditions in MODES 4 (continued)

RIVER BEND B 3.5-15 Revision No. 163

ECCS-Shutdown B 3.5.2 BASES SURVEILLANCE SR 3.5.2.3, SR 3.5.2.5, and SR 3.5.2.6 REQUIREMENTS (continued) The Bases provided for SR 3.5.1.1, SR 3.5,1.4, and SR 3.5.1.5 are applicable to SR 3.5.2.3, SR 3.5.2.5, and SR 3.5.2.6, respectively.

SR 3.5.2.4 Verifying the correct alignment for manual. power operated. and automatic valves in the ECCS flow paths provides assurance that the proper flow paths will exist for ECCS operation. This SR does not apply to valves that are locked. sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to locking.

sealing, or securing. A valve that receives an initiation signal is allowed to be in a nonaccident position provided the valve will automatically reposition in the proper stroke time. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of potentially being mispositioned are in the correct position.

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

In MODES 4 and 5, the RHR System may operate in the shutdown cooling mode to remove decay heat and sensible heat from the reactor.

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

The Surveillance is modified by a Note which exempts system vent flow paths opened under administrative control. The administrative control should be proceduralized and include stationing a dedicated individual at the system vent flow path who is in continuous communication with the operators in the control room. This individual will have a method to rapidly close the system vent flow path if directed.

REFERENCES 1. USAR, Section 6.3.3.4.

RIVER BEND B 3.5-19 Revision No. 163

RCIC System B 3.5.3 BASES BACKGROUND The RCIC pump is provided with a minimum flow, bypass line which (continued) discharges to the suppression pool. The valve in this line automatically opens to prevent pump damage due to overheating when other discharge line valves are closed. To ensure rapid delivery of water to the RPV and to minimize water hammer effects, the RCIC System discharge line "keep fill" system is designed to maintain the pump discharge line filled with water.

APPLICABLE The function of the RCtC system is to respond to transient events by SAFETY ANALYSES providing makeup coolant to the reactor. The RCIC system is not an Engineered Safety Feature system, and the safety analysis does not consider RCIC to be a system needed to mitigate the consequences of a control rod drop accident. Based on its contribution to the reduction of overall plant risk, however, the system is included in the Technical SpeCifications as required by the NRC Policy Statement.

LCO The OPERABILITY of the RCIC System provides adequate core cooling such that actuation of any of the ECCS subsystems is not required in the event of RPV isolation accompanied by a loss of feedwater flow. The RCIC System has sufficient capacity to maintain RPV inventory during an isolation event. Management of gas voids is important to RCIC system OPERABILITY.

APPLICABILITY The RCIC System is required to be OPERABLE in MODE 1, and MODES 2 and 3 with reactor steam dome pressure> 150 psig since RCIC is the primary non-ECCS water source for core cooling when the reactor is isolated and pressurized. In MODES 2 and 3 with reactor steam dome pressure s 150 pSig. and in MODES 4 and 5, RCIC is not required to be OPERABLE since the ECCS injection/spray subsystems can provide sufficient flow to the vessel.

ACTIONS A Note prohibits the application of LCO 3.0.4.b to an inoperable RCIC system. There is an increased risk associated with entering a MODE or other specified condition In the Applicability with an inoperable RCIC system and the prOVisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.

(continued)

RIVER BEND B 3.5-21 Revision No. 163

RCtC System B 3.5.3 BASES SURVEILLANCE SR 3.5.3.1 REQUIREMENTS The RCIC System flow path piping and components have the potential to develop voids and pockets of entrained gases. Preventing and managing gas intrusion and accumulation is necessary for proper operation of the RCIC System and may also prevent a water hammer. pump cavitation, and pumping of noncondensible gases.

Selection of RCIC System locations susceptible to gas accumulation is based on a self-assessment of the piping configuration to identify where gases may accumulate and remain even after the system is filled and vented, and to identify vulnerable potential degassing flow paths. The review is supplemented by verification that installed high-point vents are actually at the system high points, including field verification to ensure pipe shapes and construction tolerances have not inadvertently created additional high points. Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions.

The RCIC System is OPERABLE when it is sufficiently filled with water.

Acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location (or the volume of accumulated gas at one or more susceptible location exceeds an acceptance criteria for gas volume at the suction or discharge of a pump),

the Surveillance is not met. If it is determined by subsequent evaluation that the RCtC Systems are not rendered inoperable by the accumulated gas (Le., the system is suffiCiently filled with water), the Surveillance may be declared met. Accumulated gas should be eliminated or brought within the acceptance criteria limits.

RCIC System locations susceptible to gas accumulation are monitored and, if gas is found, the gas volume is compared to the acceptance criteria for the location. Susceptible locations in the same system flow path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representative sub-set of susceptible locations.

Monitoring may not be practical for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or (continued)

RIVER BEND B 3.5-23 Revision No. 163

RCIC System B 3.5.3 BASES (continued) personnel safety. For these locations alternative methods (e.g., operating parameters, remote monitoring) may be used to monitor the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval.

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

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

The 31 day Frequency of this SR was derived from the Inservice Testing Program requirements for performing valve testing at least every 92 days.

The Frequency of 31 days is further justified because the valves are operated under procedural control and because improper valve position would affect only the RCIC System. This Frequency has been shown to be acceptable through operating experience.

The Surveillance is modified by a Note which exempts system vent flow paths opened under administrative control. The administrative control should be proceduralized and include stationing a dedicated individual at the system vent flow path who is in continuous communication with the operators in the control room. This individual will have a method to rapidly close the system vent flow path if directed.

(continued)

RIVER BEND B 3.5-23a Revision No. 163

RHR Suppression Pool Cooling B 3.6.2.3 BASES APPLICABLE The RHR Suppression Pool Cooling System satisfies Criterion 3 of the SAFETY ANALYSES NRC Policy Statement.

(continued)

LCO During a DBA. a minimum of one RHR suppression pool cooling subsystem is required to maintain the primary containment peak pressure and temperature below the design limits (Ref. 1). To ensure that these requirements are met, two RHR suppression pool cooling subsystems must be OPERABLE. Therefore, in the event of an accident. at least one subsystem is OPERABLE, assuming the worst case single active failure.

An RHR suppression pool cooling subsystem is OPERABLE when the pump, two heat exchangers. and associated piping, valves, instrumentation, and controls are OPERABLE. Management of gas voids is important to RHR Suppression Pool Cooling System OPERABILITY.

APPLICABILITY In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to primary containment and cause a heat up and pressurization of primary containment. In MODES 4 and 5. the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, the RHR Suppression Pool Cooling System is not required to be OPERABLE in MODE 40r5.

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

(continued)

RIVER BEND B 3.6-63 Revision No. 163

RHR Suppression Pool Cooling B 3.6.2.3 BASES ACTIONS (continued) D.1 and D.2 If the required Action and required Completion Time of Condition C cannot be met or if two RHR suppression pool cooling subsystems are inoperable, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.2.3.1 REQUIREMENTS Verifying the correct alignment for manual, power operated, and automatic valves, in the RHR suppression pool cooling mode flow path provides assurance that the proper flow path exists for system operation.

This SR does not apply to valves that are locked, sealed, or otherwise secured In position since these valves were verified to be in the correct position prior to being locked, sealed, or secured. A valve is also allowed to be in the nonaccident position. provided it can be aligned to the accident position within the time assumed in the accident analysis. This is acceptable, since the RHR suppression pool cooling mode is manually initiated. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.

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

SR 3.6.2.3.2 RHR Suppression Pool Cooling System piping and components have the potential to develop voids and pockets of entrained gases. Preventing and managing gas intrusion and accumulation is necessary for proper operation of the RHR suppression pool cooling subsystems and may also prevent water hammer and pump cavitation.

(continued)

RIVER BEND B 3.6-64a Revision No. 163

RHR Suppression Pool Cooling B 3.6.2.3 BASES SURVEILLANCE SR 3.6.2.3.2 (continued)

REQUIREMENTS (continued) Selection of RHR Suppression Pool Cooling System locations susceptible to gas accumulation is based on a review of system design information, including piping and instrumentation drawings, isometric drawings, plan and elevation drawings, and calculations. The design review is supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance or restoration. Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions.

The RHR Suppression Pool Cooling System is OPERABLE when it is sufficiently filled with water. Acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location (or the volume of accumulated gas at one or more susceptible location exceeds an acceptance criteria for gas volume at the suction or discharge of a pump), the Surveillance is not met. If it is determined by subsequent evaluation that the RHR Suppression Pool Cooling System is not rendered inoperable by the accumulated gas (Le., the system is sufficiently filled with water), the Surveillance may be declared met.

Accumulated gas should be eliminated or brought within the acceptance criteria limits.

RHR Suppression Pool Cooling System locations susceptible to gas accumulation are monitored and, if gas is found, the gas volume is compared to the acceptance criteria for the location. Susceptible locations in the same system flow path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representative sub~

set of susceptible locations. Monitoring may not be practical for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or personnel safety. For these locations alternative methods (e.g., operating parameters. remote monitoring) may be used to monitor the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval.

The 31 day Frequency takes into consideration the gradual nature of gas accumulation in the RHR Suppression Pool Cooling System piping and the procedural controls governing system operation.

RIVER BEND B 3.6-64b Revision No. 163

RHR Suppression Pool Cooling B 3.6.2.3 BASES SURVEILLANCE SR 3.6.2.3.3 REQUIREMENTS (continued) Verifying each RHR pump develops a flow rate c: 5050 gpm, with flow through the associated heat exchanger to the suppression pool ensures that pump performance has not degraded during the cycle. Flow is a normal test of centrifugal pump performance required by ASME OM Code (Ref. 2). This test confirms one point on the pump design curve, and the results are indicative of overall performance. Such inservice inspections confirm component OPERABILITY, trend performance. and detect incipient failures by indicating abnormal performance. The Frequency of this SR is in accordance with the Inservice Testing Program.

REFERENCES 1. USAR, Section 6.2.

2. ASME OM Code for Operation and Maintenance of Nuclear Power Plants.

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

RIVER BEND B 3.6-65 Revision No. 163

RHR - High Water Level B3.9.8 BASES LCO An OPERABLE RHR shutdown cooling subsystem consists of an RHR (continued) pump, two heat exchangers, valves, piping. instruments, and controls to ensure an OPERABLE flow path. Management of gas voids is important to RHR Shutdown Cooling System OPERABILITY.

Additionally, each RHR shutdown cooling subsystem is considered OPERABLE if it can be manually aligned (remote or local) in the shutdown cooling mode for removal of decay heat. Operation (either continuous or intermittent) of one SUbsystem can maintain and reduce the reactor coolant temperature as required. However, to ensure adequate core flow to allow for accurate average reactor coolant temperature monitoring, nearly continuous operation is required. A Note is provided to allow a 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months exception to shut down the operating subsystem every 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

APPLICABILITY One RHR shutdown cooling subsystem must be OPERABLE in MODE 5, with irradiated fuel in the RPV and the water level ~ 23 ft above the top of the RPV flange, to provide decay heat removal. RHR System requirements in other MODES are covered by LCOs in Section 3.4, Reactor Coolant System (RCS); Section 3.5, Emergency Core Cooling Systems (ECCS) and Reactor Core Isolation COOling (RCIC) System; and Section 3.6, Containment Systems. RHR Shutdown Cooling System requirements in MODE 5, with the water level < 23 ft above the RPV flange, are given in LCO 3.9.9, "Residual Heat Removal (RHR) -Low Water Level."

ACTIONS With no RHR shutdown cooling subsystem OPERABLE, an alternate method of decay heat removal must be established within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . In this condition, the volume of water above the RPV flange provides adequate capability to remove decay heat from the reactor core. However. the overall reliability is reduced because loss of water level could result in reduced decay heat removal capability. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is based on the decay heat removal function and the probability of a loss of the available decay heat removal capabilities. Furthermore, verification of the functional availability of these alternate methodes) must be reconfirmed every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter. This will ensure continued heat removal capability.

(continued)

RIVER BEND Revision No. 163

RHR -High Water Level B 3.9.8 BASES SURVEILLANCE SR 3.9.8.1 REQUIREMENTS This Surveillance demonstrates that the RHR shutdown cooling subsystem is in operation and circulating reactor coolant. The required flow rate is determined by the flow rate necessary to provide sufficient decay heat removal capability. The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is sufficient in view of other visual and audible indications available to the operator for monitoring the RHR subsystem in the control room.

SR 3.9.8.2 RHR Shutdown Cooling System piping and components have the potential to develop voids and pockets of entrained gases. Preventing and managing gas intrusion and accumulation is necessary for proper operation of the required RHR shutdown cooling subsystem(s) and may also prevent water hammer, pump cavitation, and pumping of noncondensible gas into the reactor vessel.

Selection of RHR Shutdown Cooling System locations susceptible to gas accumulation is based on a review of system design information, including piping and instrumentation drawings, isometric drawings, plan and elevation drawings, and calculations. The design review is supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance or restoration.

Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions.

The RHR Shutdown Cooling System is OPERABLE when it is sufficiently filled with water. Acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location (or the volume of accumulated gas at one or more susceptible location exceeds and acceptance criteria for gas volume at the suction or discharge of a pump). the Surveillance is not met. If it is determined by subsequent evaluation that the RHR Shutdown Cooling System is not rendered inoperable by the accumulated gas (I.e., the system is sufficiently filled with water), the Surveillance may be declared met.

Accumulated gas should be eliminated or brought within the acceptance criteria limits.

RHR Shutdown Cooling System locations susceptible to gas accumulation are monitored and. if gas is found, the gas volume is compared to the acceptance criteria for the location. Susceptible locations in the same system flow path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representative sub-set of susceptible locations. Monitoring may not be practical for locations that are inaccessible due to radiological or environmental conditions. the plant configuration, or personnel safety. For these locations alternative (continued)

RIVER BEND B 3.9-28a Revision No. 163

RHR -High Water Level B 3.9.8 BASES SURVEILLANCE SR 3.9.8.2 (continued)

REQUIREMENTS (continued) methods (e.g., operating parameters, remote monitoring) may be used to monitor the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trend of the results should be sufficient to assure system OPERABILITY during the Surveillance interval.

The 31 day Frequency takes into consideration the gradual nature of gas accumulation in the RHR Shutdown Cooling System piping and the procedural controls governing system operation.

REFERENCES None.

RIVER BEND B 3.9-28b Revision No. 163

RHR -Low Water Level B 3.9.9 B 3.9 REFUELING OPERATIONS B 3.9.9 Residual Heat Removal (RHR)-Low Water Level BASES BACKGROUND The purpose of the RHR System in MODE 5 is to remove decay heat and sensible heat from the reactor coolant, as required by GDC 34. Each of the two shutdown cooling loops of the RHR System can provide the required decay heat removal. Each loop consists of one motor driven pump, two heat exchangers, and associated piping and valves. Both loops have a common suction from the same recirculation loop. Each pump discharges the reactor coolant, after it has been cooled by Circulation through the respective heat exchangers, to the reactor via separate feedwater lines. to the upper containment pool via a common single flow distribution sparger, or to the reactor via the low pressure coolant injection path. The RHR heat exchangers transfer heat to the normal or Standby Service Water System. The RHR shutdown cooling mode is manually controlled.

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

Although the RHR System does not meet a specific criterion of the NRC PoliCY Statement, it was identified in the NRC Policy Statement as an important contributor to risk reduction. Therefore. the RHR System is retained as a Specification.

LCO In MODE 5 with irradiated fuel in the reactor pressure vessel (RPV) and the water level < 23 ft above the RPV flange both RHR shutdown cooling subsystems must be OPERABLE.

An OPERABLE RHR shutdown cooling subsystem consists of an RHR pump, two heat exchangers, valves, piping, instruments, and controls to ensure an OPERABLE flow path. Management of gas voids is important to RHR Shutdown Cooling System OPERABILITY.

(continued)

RIVER BEND Revision No. 163

RHR - Low Water Level B 3.9.9 BASES ACTIONS C.1 and C.2 (continued) out of service. and normal decay heat removal systems are lost or intentionally turned off, especially during periods of high decay heat load.

SURVEILLANCE SR 3.9.9.1 REQUIREMENTS This Surveillance demonstrates that one RHR shutdown cooling subsystem is in operation and circulating reactor coolant. The required flow rate is determined by the flow rate necessary to provide sufficient decay heat removal capability. The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is sufficient in view of other visual and audible indications available to the operator for monitoring the RHR subsystem in the control room.

SR 3.9.9.2 RHR Shutdown Cooling System piping and components have the potential to develop voids and pockets of entrained gases. Preventing and managing gas intrusion and accumulation is necessary for proper operation of the RHR shutdown cooling subsystems and may also prevent water hammer, pump cavitation, and pumping of noncondensible gas into the reactor vessel.

Selection of RHR Shutdown Cooling System locations susceptible to gas accumulation is based on a review of system design information, including piping and instrumentation drawings. isometric drawings, plan and elevation drawings, and calculations. The design review is supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance or restoration.

Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions.

The RHR Shutdown Cooling System is OPERABLE when it is sufficiently filled with water. Acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location (or the volume of accumulated gas at one or more susceptible location exceeds and acceptance criteria for gas volume at the suction or discharge of a pump), the Surveillance is not met. If it is determined by subsequent evaluation that the RHR Shutdown Cooling System is not rendered inoperable by the accumulated gas (Le .. the system is sufficiently filled with water). the Surveillance may be declared met.

Accumulated gas should be eliminated or brought within the acceptance criteria limits.

RHR Shutdown Cooling System locations susceptible to gas accumulation are monitored and, if gas is found, the gas volume is compared to the acceptance criteria for the location. Susceptible (continued)

RIVER BEND B 3.9-32a Revision No. 163

RHR - Low Water Level B 3.9.9 BASES SURVEILLANCE SR 3.9.9.2 (continued)

REQUIREMENTS (continued) locations in the same system flow path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representative sub-set of susceptible locations. Monitoring may not be practical for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or personnel safety. For these locations alternative methods (e.g., operating parameters. remote monitoring) may be used to monitor the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval.

The 31 day Frequency takes into consideration the gradual nature of gas accumulation in the RHR Shutdown Cooling System piping and the procedural controls governing system operation.

REFERENCES None.

RIVER BEND B 3.9-32b Revision No. 163

TECHNICAL SPECIFICATIONS BASES LIST OF EFFECTIVE PAGES PAGE REV PAGE REV PAGE REV PAGE REV NUMBER NUMBER NUMBER NUMBER B 3.3-80 0 B 3.3-120 143 B 3.3-160 104 B 3.3-200 0 B 3.3-81 0 B 3.3-121 0 B 3.3-161 0 B 3.3-201 115 B 3.3-82 0 B 3.3-122 0 B 3.3-162 0 B 3.3-202 0 B 3.3-83 0 B 3.3-123 4-1 B 3.3-163 0 B 3.3-203 0 B 3.3-84 143 B 3.3-124 0 B 3.3-164 0 B 3.3-204 3-4 B 3.3-85 141 B 3.3-125 2-6 B 3.3-165 0 B 3.3-205 0 B 3.3-86 131 B 3.3-126 0 B 3.3-166 0 B 3.3-206 0 B 3.3-87 0 B 3.3-127 0 B 3.3-167 152 B 3.3-207 143 B 3.3-88 0 B 3.3-128 0 B 3.3-168 143 B 3.3-208 0 B 3.3-89 0 B 3.3-129 0 B3.3-169 0 B 3.3-209 1 B 3.3-90 0 B 3.3-130 0 B3.3-170 141 B 3.3-210 1 B 3.3-91 0 B 3.3-131 130 B 3.3-171 6-5 B 3.3-211 1 B 3.3-92 0 B 3.3-132 0 B 3.3-172 6-5 B 3.3-212 145 B 3.3-93 0 B 3.3-133 143 B 3.3-173 6-5 B 3.3-213 0 B 3.3-94 0 B3.3-134 0 B 3.3-174 110 B 3.3-214 123 B 3.3-95 0 B 3.3-135 0 B 3.3-175 6-5 B 3.3-215 143 B 3.3-96 6-12 B3.3-136 0 B 3.3-176 6-5 B 3.3-216 0 B 3.3-97 0 B 3.3-137 0 B 3.3-177 6-5 B 3.3-217 0 B 3;3-98 0 B 3.3-138 0 B 3.3-178 6-5 B 3.3-218 0 B 3.3-99 0 B 3.3-139 115 B3.3-179 6-5 B 3.3-219 0 B3.3-100 0 B 3.3-140 159 B 3.3-180 143 B 3.3-220 161 B 3.3-101 0 B 3.3-141 0 B 3.3-181 0 B 3.3-220a 161 B3.3-102 0 B 3.3-142 104 B3.3-182 0 B 3.3-221 143 B 3.3-103 0 B 3.3-143 110 B 3.3-183 1 B 3.3-222 161 B 3.3-104 0 B 3.3-144 115 B 3.3-184 0 B 3.4-1 4-8 B 3.3-105 0 B 3.3-145 2-6 B 3.3-185 0 B 3.4-2 4-8 B3.3-106 0 B 3.3-146 0 B 3.3-186 0 B 3.4-3 114 B 3.3-107 0 B 3.3-147 0 B 3.3-187 0 B 3.4-4 4-8 B 3.3-108 0 B 3.3-148 109 B 3.3-188 0 B 3.4-5 112 B3.3-109 0 B 3.3-149 0 B 3.3-189 0 B 3.4-6 4-8 B3.3-110 0 B3.3-150 109 B 3.3-190 143 B 3.4-7 4-8 B3.3-111 0 B3.3-151 0 B 3.3-191 0 B 3.4-8 4-8 B3.3-112 0 B 3.3-152 0 B3.3-192 0 B 3.4-9 0 B3.3-113 0 B 3.3-153 116 B 3.3-193 164 B 3.4-10 0 B 3.3-114 0 B3.3-154 0 B 3.3-194 0 B 3.4-11 143 B 3.3-115 0 B3.3-155 0 B3.3-195 0 B 3.4-12 143 B3.3-116 0 B3.3-156 0 B 3.3-196 143 B 3.4-13 0 B3.3-117 103 B3.3-157 115 B 3.3-197 164 B 3.4-14 0 B 3.3-118 0 B 3.3-158 115 B 3.3-198 144 B3.4-15 0 B3.3-119 0 B 3.3-159 139 B 3.3-199 144 B 3.4-16 6-7 B3.4-17 1 RIVER BEND TSB-b Revision No. 164

Relief and LLS Instrumentation B 3.3.6.4 BASES LCO successfully accomplishing the relief and LLS function, assuming any (continued) single instrumentation channel failure within the LLS logic. Therefore, two trip systems are required to be OPERABLE. The OPERABILITY of each trip system is dependent upon the OPERABILITY of the reactor steam dome pressure channels associated with required relief and LLS S/RVs.

Each required channel shall have its setpoint within the specified Allowable Value. A channel is inoperable if its actual trip setpoint is not within its required Allowable Value. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions.

Allowable Values are specified for each channel in SR 3.3.6.4.3. Nominal trip setpoints are specified in the setpoint calculations. The nominal setpoints are selected to ensure that the setpoints do not exceed the Allowable Value between CHANNEL CALIBRATIONS. Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable.

Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel pressure), and when the measured output value of the process parameter exceeds the setpoint, the associated device (e.g., trip unit) changes state. The analytic limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytic limits, corrected for calibration, process, and some of the instrument errors. The trip setpoints are then determined, accounting for the remaining instrument errors (e.g., drift). The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.

For relief, the actuating Allowable Values are based on the transient event of main steam isolation valve (MSIV) closure with an indirect scram (Le., neutron flux). This analysis is described in Reference 2. For LLS, the actuating and reclosing Allowable Values are based on maintaining certain differences between the normal relief function set points. This is described in Reference 1.

(continued)

RIVER BEND B 3.3-193 Revision No. 164

Relief and LLS Instrumentation B 3.3.6.4 BASES (continued)

REFERENCES 1. NEDC-32778P, Section 5.3.3, "Safety Analysis Report for River Bend 5% Power Uprate," (RBS number 7222.250-000-046A),

5/15/00.

2. USAR, Appendix 5A.

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

RIVER BEND B 3.3-197 Revision No. 164

TECHNICAL SPECIFICATIONS BASES LIST OF EFFECTIVE PAGES PAGE REV PAGE REV PAGE REV PAGE REV NUM8ER NUM8ER NUM8ER NUM8ER 82.0-1 0 83.1-21 0 83.3-1 0 83.3-3ge 101 82.0-2 159 8 3.1-22 5-2 8 3.3-2 6-7 8 3.3-39f 4-8 82.0-3 162 83.1-23 0 83.3-3 0 83.3-39g 4-8 82.0-4 6-15 83.1-24 139 83.3-4 0 83.3-39h 4-8 82.0-5 115 83.1-25 107 83.3-5 0 83.3-40 0 8 2.0-6 115 83.1-26 139 83.3-6 0 83.3-41 6-13 8 2.0-7 0 83.1-27 0 8 3.3-7 6-4 83.3-42 6-6 82.0-8 115 83.1-28 0 83.3-8 4-8 83.3-43 6-13 82.0-9 115 83.1-29 6-14 83.3-8a 4-8 83.3-44 0 83.0-1 150 83.1-30 6-14 83.3-8b 4-8 83.3-45 0 8 3.0-2 0 83.1-31 6-14 83.3-9 4-8 83.3-46 0 83.0-3 0 83.1-32 0 83.3-10 4-8 83.3-47 143 83'.0-4 0 83.1-33 6-13 83.3-11 1 83.3-48 6-13 83.0-5 133 83.1-34 6-13 83.3-12 0 83.3-49 1 83.0-5a 158 83.1-35 6-13 83.3-13 6-4 83.3-50 0 83.0-5b 133 83.1-36 0 83.3-14 0 83.3-51 1 83.0-6 133 83.1-37 143 83.3-15 0 83.3-52 116 8 3.0-7 0 83.1-38 143 83.3-16 0 83.3-53 6-2 83.0-8 166 83.1-39 0 83.3-17 2-7 83.3-54 122 8 3.0-9 150 83.1-40 0 83.3-18 1 83.3-55 133 83.0-9a 158 83.1-41 5-6 83.3-19 1 83.3-56 133 83.9-9b 150 83.1-42 1 83.3-20 1 83.3-57 0 83.0-10 0 83.1-43 143 83.3-21 1 83.3-58 0 83.0-11 0 83.1-44 143 83.3-22 1 83.3-59 143 83.0-12 108 83.1-45 115 83.3-23 1 83.3-60 0 83.0-13 161 83.1-46 118 83.3-24 1 83.3-61 147 83.0-13a 158 83.1-47 118 83.3-25 6-4 83.3-62 133 83.0-14 133 83.1-48 0 83.3-25a 4-8 83.3-63 0 83.0-15 133 83.1-49 143 83.3-26 4-8 83.3-64 143 83.1-1 0 83.2-1 0 83.3-27 6-15 83.3-65 0 83.1-2 0 8 3.2-2 6-4 83.3-28 143 83.3-66 124 83.1-3 0 83.2-3 6-4 83.3-29, 143 83.3-67 124 83.1-4 0 8 3.2-4 3-7 83.3-30 143 83.3-68 1 83.1-5 0 83.2-5 0 83.3-31 143 83.3-69 1 83.1-6 0 83.2-6 6-15 83.3-31a 4-8 83.3-70 124 83.1-7 3-10 83.2-7 6-4 83.3-32 0 83.3-71 124 83.1-8 3-10 8 3.2-8 6-15 83.3-33 0 83.3-72 1 83.1-9 3-10 83.2-9 0 83.3-34 0 83.3-73 143 83.1-10 3-10 83.2-10 6-4 83.3-35 0 83.3-74 143 83.1-11 3-10 83.2-11 6-4 83.3-36 136 83.3-75 2-1 83.1-12 0 83.2-12 4-8 83.3-37 0 83.3-76 0 83.1-13 0 83.2-13 4-8 83.3-38 0 83.3-77 106 83.1-14 0 83.2-14 4-8 83.3-39 143 83.3-78 a 83.1-15 136 83.2-15 4-8 83.3-39a 4-8 83.3-79 a 83.1-16 0 83.2-16 4-8 83.3-39b 162 83.1-17 6-13 83.2-17 4-8 83.3-39c 4-8 83.1-18 136 83.2-18 4-8 83.3-39d 4-8 83.1-19 1 83.1-20 0 RIVER8END TS8-a Revision No. 166

LCO Applicability B 3.0 BASES LCO 3.0.6 potential confusion and inconsistency of requirements related to the entry (continued) into multiple support and supported systems' LCO's Conditions and Required Actions are eliminated by providing all the actions that are necessary to ensure the plant is maintained in a safe condition in the support system's Required Actions.

However, there are instances where a support system's Required Action may either direct a supported system to be declared inoperable or direct entry into Conditions and Required Actions for the supported system.

This may occur immediately or after. some specified delay to perform some other Required Action. Regardless of whether it is immediate or after some delay, when a support system's Required Action directs a supported system to be declared inoperable or directs entry into Conditions and Required Actions for a supported system, the applicable Conditions and Required Actions shall be entered in accordance with LCO 3.0.2.

Specification 5.5.10, "Safety Function Determination Program" (SFDP).

ensures loss of safety function is detected and appropriate actions are taken. Upon failure to meet two or more LCOs concurrently, an evaluation shall be made to determine if loss of safety function exists.

Additionally, other limitations, remedial actions, or compensatory actions may be identified as a result of the support system inoperability and corresponding exception to entering supported system Conditions and Required Actions. The SFDP implements the requirements of LCO 3.0.6.

Cross division checks to identify a loss of safety function for those support systems that support safety systems are required. The cross division check verifies that the supported systems of the redundant OPERABLE support system are OPERABLE, thereby ensuring safety function is retained. If this evaluation determines that a Joss of safety function exists, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered.

LCO 3.0.7 There are certain special tests and operations required to be performed at various times over the life of the unit. These special tests and operations are necessary to (continued)

RIVER BEND B 3.0-8 Revision No. 166

TECHNICAL SPECIFICATIONS BASES LIST OF EFFECTIVE PAGES PAGE REV PAGE REV PAGE REV PAGE REV NUM8ER NUM8ER NUM8ER NUM8ER 8 3.6~90 6*5 83.6-130 2*4 83.7*28 143 83.8-35 0 83.6-91 115 83.6-131 2-4 83.7-29 115 83.8-36 0 83,6-92 6-5 83.6-132 3-4 83.7-30 0 83.8-37 115 83,6-93 115 83.6-133 3-4 83.7-31 115 83.8-38 110 B 3.6-94 143 83.6-134 2-8 83.8-1 0 83.8*39 102 83.6-95 6*5 83.6-135 143 8 3.8-2 5-3 83.8-40 102 83.6-96 159 83.6-136 6-2 8 3.8-3 0 83.8-41 3-2 83.6-97 159 B 3.6-137 2-8 8 3.8-4 153 83,8-42 0 83.6-98 161 83.6-138 2-8 83.8-4a 154 83.8-43 0 83.6-98a 161 83.6-139 2-8 8 3.8-5 154 83.8-44 0 B 3.6-99 159 83.6-140 2-8 83.8-6 154 83.8*45 155 83.6-100 161 83.6-141 2-8 8 3.8-7 154 B 3.8-46 0 83.6-101 121 B 3.6-142 2-8 B 3.8-8 167 B 3.8*47 0 B 3,6-102 121 B 3.7-1 110 83.8-8a 154 83.8-48 3*2 B 3.6-103 121 B 3.7-2 110 8 3.8-9 154 B 3.8-49 134 83.6-104 6*5 B 3.7-3 110 83.8-10 154 B 3.8-50 0 83.6*105 110 83.7-4 1 B 3.8-11 154 83.8-51 125 B 3.6-106 0 8 3.7*5 1 83.8-12 154 83,8-51a 125 B 3.6-107 6-5 83.7-6 161 B 3.8-13 161 83.8*52 125 B 3.6-108 6-5 B 3.7-6a 161 83.8-13a 161 B 3.8-52a 125 B 3.6-109 6-5 B 3.7-7 3-1 B 3.8-14 127 B 3.8-52b 148 B 3.6-110 6-5 B 3.7-8 143 B 3.8-15 162 B 3.8-53 161 83.6-111 6-5 B 3.7-9 161 83.8-16 151 B 3,8-53a 161 B 3.6-112 159 B 3.7-10 159 B 3.8-17 102 B 3.8-54 161 83,6-113 110 B 3.7-11 159 B 3.8-18 153 83.8-55 143 83.6-114 6-5 B 3.7-12 132 B 3.8-18a 153 B 3.8-56 143 B 3.6-115 159 B 3.7-12a 161 B 3.8-19 157 B 3.8-57 120 B 3.6-116 143 83.7-13 161 B 3,8-20 143 83,8-58 161 B 3.6-117 0 B 3.7-13a 161 83,8-21 143 B 3.8-59 110 83.6-118 0 B 3.7-14 159 B 3.8-22 113 B 3.8-60 110 B 3.6-119 143 83.7-15 143 B 3,8-23 143 B 3.8-61 115 B 3.6-120 167 B 3.7-16 161 B 3.8-24 143 83.8-62 0 83.6-121 1'19 83.7-17 157 83.8-25 162 83,8-63 0 B 3.6-122 2-4 B 3.7*18 110 83.8-26 151 B 3.8*64 0 B 3.6-123 2-4 B 3.7-19 161 B 3.8-27 143 B 3.8-65 0 B 3.6-124 2-4 B 3.7-19a 161 B 3.8-28 143 B 3.8-66 1 B 3.6-125 2-4 B 3,7-20 115 B 3,8-29 143 83.8-67 4-5 B 3,6-126 2-4 B 3.7-21 161 B 3,8-30 143 83.8-68 4-5 B 3.6-127 2-4 B 3.7-22 0 B 3,8-31 102 B 3.8-69 1 83.6-128 143 83.7-23 161 B 3.8-32 161 83.6-129 3-4 B 3.7*24 161 83.8-33 3-1 83.7*25 137 83.8-34 110 B 3.7-26 137 B 3.7-27 143 RIVER BEND TSB-d Revision No. 167

Drywall B 3.6.5.1 BASES SURVEILLANCE SR 3.6.5.1.3 REQUIREMENTS (continued) The analyses in Reference 1 are based on a maximum drywell bypass leakage. This Surveillance ensures that the actual drywell bypass leakage is less than or equal to the acceptable Al\R design value of 0.81 fF. As left drywell bypass leakage, prior to the first startup after performing a required drywell bypass leakage test, is required to be

$; 10<% of the drywell bypass leakage limit. At aU other times between required drywell leakage rate tests, the acceptance criteria is based on design A/\R. At the design A/\R the containment temperature and pressurization response are bounded by the assumptions of the safety analysis. Due to NRC Generic Letter 96~06 concerns, integrity of the reactor recirculation flow control valve hydraulic power unit (HPU) penetrations cannot be assumed. For this reason, 0.0164tr is added to the drywell bypass leakage surveillance result (Ref. 3). This surveillance is performed at least once every 15 years on a performance based frequency. The frequency is consistent with the difficulty of performing the test, risk of high radiation exposure, and the remote possibility that sufficient component failures will occur such that the drywell bypass leakage limit will be exceeded. if during the performance of this required Surveillance the drywell bypass leakage rate is greater than the drywell bypass leakage limit, the Surveillance Frequency is increased to every 48 months. If during the performance of the subsequent consecutive Surveillance the drywell bypass leakage rate is less than or equal to the drywell bypass leakage limit, the 15 year Frequency may be resumed. If during the performance of two consecutive Surveillances the drywell bypass leakage is greater than the drywell bypass leakage limit, the Surveillance Frequency is increased to at least once every 24 months.

The 24 month Frequency is maintained until during the performance of two consecutive Surveillances the drywell bypass leakage rate is less than or equal to the drywell bypass leakage limit, at which time the 15 year Frequency may be resumed. For two Surveillances to be considered consecutive, the Surveillances must be performed at least 12 months apart. Since the frequency is performance based, the Frequency was concluded to be acceptable from a reliability standpoint SR 3.6.5.1.4 The exposed accessible drywell interior and exterior surfaces are inspected to ensure there are no apparent physical defects that would prevent the drywell from (continued)

R!VER BEND B 3.6-120 Revision No. 167

AC Sources-- Operating B 3.8.1 BASES ACTIONS C.3.1 and C.3.2 (continued) is satisfied. If the cause of the initial inoperable DG cannot be confirmed not to exist on the remaining DG(s), performance of SR 3.8.1.2 suffices to provide assurance of continued OPERABILITY of those DG(s).

In the event the inoperable DG is restored to OPERABLE status prior to completing either C.3.1 or C.3.2, the Condition Report Program will continue to evaluate the common cause possibility. This continued evaluation, however, is no longer under the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months constraint imposed while in Condition C.

If while a DG is inoperable, a new problem with the DG is discovered that would have prevented the DG from performing its specified safety function, a separate entry into Condition B is not required. The new DG problem should be addressed in accordance with the Condition Report Program.

According to Generic Letter 84-15 (Ref. 7), 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is reasonable time to confirm that the OPERABLE DG(s) are not affected by the same problem as the inoperable DG.

CA In Condition C, the remaining OPERABLE DGs and offsite circuits are adequate to supply electrical power to the onsite Class 1E distribution system. Although Condition C applies to a single inoperable DG, several Completion Times are Specified for this Condition. The first completion time applies to an inoperable Division III oG. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and low probability of a DBA occurring during this period. This Completion Time begins only "upon discovery of an inoperable Division III DG" and. as such, provides an exception to the normal "time zero" for beginning the allowed outage time "clock" (Le., for beginning the clock for an inoperable Division III oG when Condition C may have already been entered for another equipment inoperability and is still in effect).

The second Completion Time (14 days) applies to an inoperable Division I or Division II DG and is risk-informed allowed out-of-service time (AOT) based on plant specific risk analysis, The extended AOT would typically be use for voluntary planned maintenance or inspections but can also be used for corrective maintenance. However, use of the extended AOT for voluntary planned maintenance should be limited to once within an 18-month period for each DG (Division I and Division II). Additional contingencies are to be in place for any extended AOT duration (greater than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and up to 14 days) as follows:

1. An DG extended AOT wi!! not be entered for voluntary planned maintenance purposes if severe weather conditions are expected.

(continued)

RIVER BEND B 3.8-8 Revision No. 167

TECHNICAL SPECIFICATIONS BASES LIST OF EFFECTIVE PAGES PAGE REV PAGE REV PAGE REV PAGE REV NUMBER NUMBER NUMBER NUMBER B 3.6-90 6-5 B 3.6-130 2-4 B 3,7-28 143 83.8-35 0 83.6-91 115 B 3,6-131 2-4 B 3.7-29 115 83.8-36 0 83,6-92 6-5 B 3,6-132 3-4 B 3.7-30 0 83.8-37 115 83.6-93 115 83.6-133 3-4 B 3.7-31 115 83.8-38 110 83.6-94 143 B 3.6-134 2-8 83.8-1 0 83.8-39 102 83.6-95 6-5 83.6-135 143 83.8-2 5-3 83.8-40 102 83.6-96 159 83.6-136 6-2 83.8-3 0 83.8-41 3-2 83.6-97 159 83.6-137 2-8 83.8-4 153 83.8-42 0 83.6-98 161 83.6-138 2-8 83.8-4a 154 83.8-43 0 83.6-9Sa 161 83.6-139 2-8 8 3.8-5 154 83.8-44 0 83.6*99 159 83.6-140 2-8 83.8-6 154 B 3.8-45 155 83.6-100 161 83.6-141 2-8 8 3.8-7 154 83.8-46 0 83.6-101 121 83.6-142 2-8 8 3.8-8 168 83.8-47 0 83.6-102 121 B 3.7-1 110 B S.8-Sa 154 83.8-48 3-2 83.6-103 121 B 3.7-2 110 B 3.8-9 154 83.8-49 134 B 3.6-104 6-5 B 3.7-3 110 83.8-10 154 83.8-50 0 B 3.6-105 110 83.7-4 1 83.8-11 154 B 3.8-51 125 83.6-106 0 83.7-5 1 B 3.8-12 154 83.8-51a 125 83.6-107 6-5 83.7-6 161 B 3.8-13 161 83.8-52 125 83.6-108 6-5 83.7-6a 161 83.8-13a 161 83.8-52a 125 83.6-109 6-5 83.7-7 3-1 83.8-14 127 B 3.8-52b 148 83.6-110 6-5 83.7-8 143 83.8-15 162 83.8-53 161 83.6-111 6-5 83.7-9 161 83.8-16 151 83.8-53a 161 83.6-112 159 83.7-10 159 83.8-17 102 83.8-54 161 83.6-113 110 83.7-11 159 83.8-18 153 83.8-55 143 B 3.6-114 6-5 83.7-12 132 B 3.8-18a 153 83.8-56 143 83.6-115 159 B 3.7-12a '161 B 3.8-19 157 83.8-57 120 83.6-1 '16 143 83.7-13 161 83.8-20 143 83.8-58 161 83.6-117 0 83.7-13a 161 83.8-21 143 83.8-59 110 83.6-118 0 83.7-14 159 83.8-22 113 83.8-60 110 83.6-119 143 83.7-15 143 83.8-23 143 B 3.8-61 115 83.6-120 167 83.7-16 161 B 3.8-24 143 B 3.8-62 0 83.6-121 119 83.7-17 157 B 3.8-25 162 B 3.8-63 0 83.6-122 2-4 83.7-18 110 83.8-26 151 83.8-64 0 B 3.6-123 2-4 83.7-19 161 83.8-27 143 B 3.8-65 0 83.6-124 2-4 83.7-19a 161 83.8-28 143 83.8-66 1 83.6-125 2-4 83.7-20 115 B 3.8-29 143 83.8-67 4-5 B 3.6-126 2-4 83.7-21 161 83.8-30 143 83.8-68 4-5 B 3.6-127 2-4 83.7-22 0 83.8-31 102 B 3.8-69 1 B 3.6-128 143 B 3.7-23 161 83.8-32 161 83.6-129 3-4 B 3.7-24 161 83.8-33 3-1 83.7-25 137 83,8-34 110 B 3.7-26 137 B 3.7-27 143 RIVER8END TS8-d Revision No. 168

AC Sources - Operating B 3.8.1 BASES ACTIONS C.3.1 and C.3.2 (continued) is satisfied. If the cause of the initial inoperable DG cannot be confirmed not to exist on the remaining DG(s). performance of SR 3.8.1.2 suffices to provide assurance of continued OPERABILITY of those DG(s).

In the event the inoperable DG is restored to OPERABLE status prior to completing either C.3.1 or C.3.2, the Condition Report Program will continue to evaluate the common cause possibility. This continued evaluation, however, is no longer under the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months constraint imposed while in Condition C.

If while a DG is inoperable, a new problem with the DG is discovered that would have prevented the DG from performing its specified safety function. a separate entry into Condition C is not required. The new DG problem should be addressed in accordance with the Condition Report Program.

According to Generic Letter 84-15 (Ref. 7), 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is reasonable time to confirm that the OPERABLE DG(s) are not affected by the same problem as the inoperable DG.

In Condition C, the remaining OPERABLE DGs and offsite circuits are adequate to supply electrical power to the onsite Class 1E distribution system. Although Condition C applies to a single inoperable DG, several Completion Times are Specified for this Condition. The first completion time applies to an inoperable Division III DG. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and low probability of a DBA occurring during this period. This Completion Time begins only "upon discovery of an inoperable Division III DG" and, as such, provides an exception to the normal "time zero" for beginning the allowed outage time "clock" (Le., for beginning the clock for an Inoperable Div1sion III DG when Condition C may have already been entered for another equipment Inoperabi!ity and is still in effect).

The second Completion Time (14 days) applies to an Inoperable Division I or Division II DG and is risk-informed allowed out-of-service time (AOT) based on plant specific risk analysis. The extended AOT would typically be use for voluntary planned maintenance or inspections but can also be used for corrective maintenance. However, use of the extended AOT for voluntary planned maintenance should be limited to once within an 18-month period for each DG (Division I and Division II). Additional contingencies are to be in place for any extended AOT duration (greater than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and up to 14 days) as follows:

1. An DG extended AOT will not be entered for voluntary planned maintenance purposes if severe weather conditions are expected.

(continued)

RIVER BEND B 3.8-8 Revision No. 168

RBG-47775, Revisions to the Technical Requirements Manual and the Technical Specification Bases

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