ML19106A160

Submittal of Changes to Technical Specifications Bases

ML19106A160
Person / Time
Site:	Limerick
Issue date:	04/12/2019
From:	David Helker Exelon Generation Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML19106A160 (311)

Text

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• 7 Exelon Generation 200 Exelon Way Kennett Square. PA 19348 www.exeloncorp.com TS 6.8.4.h.d April 12, 2019 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555 Limerick Generating Station, Units 1 and 2 Renewed Facility Operating License Nos. NPF-39 and NPF-85 NRC Docket Nos. 50-352 and 50-353

Subject:

Submittal of Changes to Technical Specifications Bases In accordance with the requirement of Limerick Generating Station (LGS), Units 1 and 2 Technical Specification 6.8.4.h.d, Exelon Generation Company, LLC, hereby submits a complete updated copy of the Unit 1 and Unit 2 Technical Specifications Bases, which includes changes through the date of this letter.

If you have any questions or require further information, please contact Glenn Stewart at 610-765-5529.

Sincerely, David P. Helker Manager, Licensing & Regulatory Affairs Exelon Generation Company, LLC

Enclosures:

1) LGS Unit 1 Technical Specifications Bases

2) LGS Unit 2 Technical Specifications Bases cc: USNRC Region I, Regional Administrator (w/o enclosures)

USNRC Senior Resident Inspector, LGS (w/o enclosures)

USNRC Senior Project Manager, LGS (w/o enclosures)

R. R. Janati, Bureau of Radiation Protection (w/o enclosures)

LIMERICK GENERATING STATION UNIT 1 TECHNICAL SPECIFICATION PAGE REVISION LIST Index Amendment Nos.

i 66 ii 207 iii 66 iv 33 V 37 vi 66 via Deleted vii 186 viii 186 ix 186 X 228 xi 199 xii 146 xiii 173*

xiv 189 xv 209 xvi 1"33 xvii 228 xviii 69 xix 228 xx Associated with Amendment 216 xxi 188 xxii 133 xxiii 2~8 xxiv 48 XXV Original Issue xxvi 176 xxvii 192 xxviii 219 Section 1.0 Definitions 1-1 Original Issue 1-2 185 1-3 225 1-4 187 1-5 146 1-6 229 1-7 229 1-8 187 1-9 71 J 1-10 149 LIMERICK - UNIT 1 -A- REVISED THRU AMENDMENT 233 EXCEPT IMPLEMENTATION OF AMENDMENT 227

LIMERICK GENERATING STATION UNIT 1 TECHNICAL SPECIFICATION PAGE REVISION LIST Index Amendment Nos.

C Section 2.0 Safety Limits and Limiting Safety System Settings 2-1 222 2-2 Original Issue 2-3 141 2-4 201 Bases for Section 2.0 B 2-1 222 B 2-2 ECR 11-00092 B 2-3 7 B 2-4 7 B 2-5 33 B 2-6 177 B 2-7 Associated with Amendment 201 B 2-7a- Associated with Amendment 201 B 2-8 89 B 2-9 Original Issue B 2-10 177 Sections 3.0 and 4.0 Limiting Conditions for Operation and Surveillance Requirements 3/4 0 226 3/4 0-1a 219 3/4 0-2 226 3/4 0-3 225 3/41-1 Original Issue 3/4 1-2 207 3/4 1-3 178 3/4 1-4 186 3/4 1-5 186 3/4 1-6 186 3/4 1-7 Original Issue 3/4 1-8 169 3/4 1-9 143 3/4 1-10 186 3/4 1-11 192 3/4 1-12 ------ f92 3/4 1-13 169 3/4 1-14 186 3/4 1-15 Original Issue 3/4 1-16 17 LIMERICK - UNIT 1 . B. REVISED THRU AMENDMENT 233 EXCEPT IMPLEMENTATION OF AMENDMENT 227

LIMERICK GENERATING STATION

- UNIT 1 TECHNICAL SPECIFICATION PAGE REVISION LIST Index Amendment Nos.

3/4 1-17 17 3/4 1-18 . 186 3/4 t-19 201 3/4 1-20 232 3/4 1-21 232 3/4 1-22 22 3/4 2-1 186 3/4 2:2 37

. 3/4 2-3 thru 3/4 2-6c Deleted 3/4 2-7

• 66 3/4 2-8 66 3/4 2-9 186 3/4 2-10 37 3/4 2-10a thru 3/4 2-10c Deleted 3/42-11 Deleted 3/4 2-12 186 3/4 3-1 233 3/4 3-1 a 186 3/43-2 177

\  !,..

.._,, 3/4 3-3 89 3/4 3-4 200 3/4 3-5 2ot 3/4 3-6 177 3/4 3-7 201 3/43-8 233 3/4 3-8a 201 3/4 3-9 169 3/4 3-10 186 3/43-11 89 3/4 3-12 Original Issue 3/4 3-13 33 3/4 3-14 112 3/4 3-15 112 3/4 3-16 185 3/4 3-17 146 3/4 3-18 222 3/4 3-19 213 3/4 3-20 213 3/4 3-21 112 3/43-22 112 3/4 3-23 214 3/4 3-24 132 3/4 3-25 132 LIMERICK - UNIT 1 -C- REVISED THRU AMENDMENT 233 EXCEPT IMPLEMENTATION OF AMENDMENT 227

LIMERICK GENERATING STATION UNIT 1 TECHNICAL SPECIFICATION PAGE REVISION LIST Index Amendment Nos. C 3/4 3-26 146 3/4 3-27 186 3/4 3-28 186 3/4 3-29 186 3/4 3-30 186 3/4 3-31 186 3/4 3-32 186 3/4 3-33 224 3/4 3-34 33 3/4 3-35 224 3/4 3<~6 158 3/4 3-36.a 158 3/4 3-37 33 3/4 3-38 18 3/4 3-39 132 3/4 3-40 186 3/4 3-41 186 3/4 3-42 186 3/4 3-43 3/4 3-44 3/4 3-45 3/4 3-46 70 106 186 201 c:~

3/4 3-47 186 3/4 3-48 201 3/4 3-49 Original Issue 3/4 3-50 Original Issue 3/4 3-51

• 186 3/4 3-52 186 3/4 3-53 224 3/4 3-54 53 3/4 3-55 33 3/4 3-56 186 3/4 3-57 186 3/4 3-58 177 3/4 3-59 141 3/4 3-60 201 3/4 3-60a 177 3/4 3-60b 34 3/4 3-61 186 3/4 3-62 186 3/4 3-63 186

/

3/4 3-64 185 3/4 3-65 185 L LIMERICK - UNIT 1

• D. REVISED THRU AMENDMENT 233 EXCEPT IMPLEMENTATION OF AMENDMENT 227

LIMERICK GENERATING STATION UNIT 1 TECHNICAL SPECIFICATION PAGE REVISION LIST

.)

Index Amendment Nos.

3/4 3-66 186 3/4 3-67 186

• 3/4 3-68 192 3/4 3-69 thru 3/4 3-72 Deleted 3/4 3-73 48 3/4 3-74 thru 3/4 3-75 Deleted 3/4 3-76 186 3/4 3-77 45 3/4 3-78 33 3/4 3-79 Original Issue 3/4 3-80 74 3/4 3-81 33 3/4 3-82

• Original Issue 3/4 3-83 186 3/4 3-84 186 3/4 3-85 191 3/4 3-86 173 3/4 3-87 191 3/4 3-88 186

)

,* 3/4 3-89 117 3/4 3,.90 186 3/4 3-91 186 3/4 3-92 104 3/4 3-92a thru 3/4 3-96 Deleted 3/4 3-97 153 3/4 3-98 48 3/4 3-99 thru 3/4 3-102 Deleted 3/4 3-103 228 3/4 3-104 . Deleted 3/4 3-105 Deleted

-3/4 3-106 Deleted 3/4 3-107 Deleted 3/4 3-108 Deleted 3/4 3-109 48 3/4 3-110 192 3/4"3-111 Deleted 3/4 3-112 186 3/4 3-113 91 3/4 3-114 Original Issue 3/4 3-115 186

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LIMERICK - UNIT 1 - E- REVISED THRU AMENDMENT 233 EXCEPT IMPLEMENTATION OF AMENDMENT 227

LIMERICK GENERATING STATION UNIT 1 TECHNICAL SPECIFICATION PAGE REVISION LIST Index Amendment Nos.

3/4 4-1 201 3/4 4-1a 177 3/4 4-2 201 3/4 4-3 177 3/44-4 196 3/4 4-4a 196 3/4 4-5 186 3/4 4-6 Originaf Issue 3/4 4-7 186 3/44-8 208 3/4 4-8a 205 3/4 4-9 182 3/4 4-10 186 3/4 4-11 182 3/4 4-12 174 3/4 4-13 Deleted 3/4 4-14 Deleted 3/4 4-15 174 3/4 4-16 20 3/4 4-17 186 c**~-

3/4 4-18 186 3/4 4-19 186 3/4 4-20 163 3/4 4-21 167 3/4 4-22 186 3/4 4-23 169 3/4 4-24 199 3/4 4-25 216 3/4 4-26 216 3/4 5-1 192 3/4 5-2 131 3/4 5-3 211 3/4 5-4 216 3/4 5-5 186 3/4 5-6 95 3/4 5-7 186 3/4 5-8 Original Issue 3/4 5-9 186 3/4 6-1 186 3/4 6-2 146 3/4 6-3 185 3/4 6-4 118 (_.

3/4 6-5 169 LIMERICK - UNIT 1 -F- . REVISED THAU AMENDMENT 233 EXCEPT IMPLEMENTATION OF AMENDMENT 227

• l LIMERICK GENERATING STATION UNIT 1 TECHNICAL SPECIFICATION PAGE REVISION LIST Index Amendment Nos.

3/4 6-6 186 3/4 6-7 225 3/4 6-8 211 3/4 6-9 186 3/4 6-10 186 3/4 6-11 186 3/4 6-12 29 3/4 6-13 186 3/4 6-14 186 3/4 6-15 216 3/4 6-16 216 3/4 6-17 192 3/4 6-18 186 3/4 6-19 146 3/4 6-20 thru 3/4 6-43a Deleted 3/4 6-44 46 3/4 6-45 186 3/4 6-46 229 3/4 6-47 229 3/4 6-48 186 3/4 6-49 192 3/4 6-50 186 3/4 6-51 192 3/4 6-51a 192 3/4 6-52 200 3/4 6-53 186 3/4 6-54 122 3/4 6-55 186 3/4 6-56 186 3/4 6-57 173 3/4 6-58 186 3/4 6-59 186 3/4 7-1 203 3/4 7-1a 203 3/4 7-2 186 3/4 7-3 203 3/4 7-4 192 3/4 7-5 186 3/4 7-6 188 3/4 7-7 188 3/4 7-8 188 J 3/4 7-9 216 LIMERICK - UNIT 1 -G- REVISED THRU AMENDMENT 233 EXCEPT IMPLEMENTATION OF AMENDMENT 227

LIMERICK GENERATING STATION UNIT 1 TECHNICAL SPECIFICATION PAGE REVISION LIST Index Amendment Nos.

C 3/4 7-10 186 3/4 7-11 223 3/47-11a 223 3/4 7-11 b Deleted 3/4 7-12 223 3/4 7-13 Deleted 3/4 7-14 Deleted 3/4 7-15 Deleted 3/4 7-16 Deleted 3/4 7-17 186 3/4 7-18 211 3/4 7-19 104 3/4 7-20 thru 3/4 7-32 Deleted 3/4 7-33 186 3/4 8-1 203 3/4 8-1 a 189 3/4 8-2 203 3/4 8-2a 189 3/4 8-3 189 3/4 8-4 189 3/4 8-5 186 3/4 8-6 186 3/4 8-7 186 3/4 8-7a 189 3/4 8-8 189 3/4 8-9 193 3/4 8-10 164 3/4 8-10a 164 3/4 8-11 186 3/4 8-12 186 3/4 8-13 164 3/4 8-14 164 3/4 8-14a 164 3/4 8-15 131 3/4 8-16 24 3/4 8-16a 139 3/4 8-17 186 3/4 8-18 24 3/4 8-18a 24 3/4 8-19 139 3/4 8-20 186 3/4 8-21 192 \, __ .

3/4 8-22 thru 3/4 8-26 Deleted LIMERICK - UNIT 1 -H- REVISED THAU AMENDMENT 233 EXCEPT IMPLEMENTATION OF AMENDMENT 227

LIMERICK GENERATING STATION UNIT 1 TECHNICAL SPECIFICATION PAGE REVISION LIST

.' ;_)

Index Amendment Nos.

3/4 8-27 209 3/4 8-28 186 3/4 9-1 149 3/4 9-2 186 3/4 9-3 186 3/4 9-4 186 3/4 9-5

• 186 3/4 9-6 Original Issue 3/4 9-7 186 3/4 9-8 43 3/4 9-9 43 3/4 9-10 186 3/4 9-1 ~ 186 3/4 9~12* 18Q 3/4 9-13 Original Issue 3/4 9-14 186 3/4 9-15 Original Issue 3/4 9-16 186 3/4 9-17 216 3/4 9-18 216 3/4 10-1 186 3/410-2 17 3/4 10-3 186 3/4 10-4 186 3/4 10-5 186 3/4 10-6 186 3/4 10-7 133 3/4 10-8 133 3/4 11-1 48 3/4 11-2 thru 3/4 11-6 Deleted 3/4 11-7 186 3/4 11-8 48 3/4 11-9 thru 3/4 11-14 Deleted 3/4 11-15 228 3/4 11-16 228 3/411-17 48 3/4 11-18 48 3/4 11-19 thru 3/4 11-20 Deleted 3/4 12-1 48 3/4 12-2 thru 3/4 12.:14 Deleted J

LIMERICK - UNIT 1 - I- REVISED THRU AMENDMENT 233 EXCEPT IMPLEMENTATION OF AMENDMENT 227

LIMERICK GENERATING STATION UNIT 1 TECHNICAL SPECIFICATION PAGE REVISION LIST Index Amendment Nos. C Bases for Sections 3.0 and 4.0 B 3/4 0-1 11 B 3/4 0-2 Associated with Amendment 226 B 3/4 0-3 Associated with Amendment 226 B 3/4 0-3a Associated with Amendment 226 B 3/4 0-3a1 Associated with Amendment 226 B 3/4 0-3b Associated with Amendment 226 B 3/4 0-3b1 Associated with Amendment 226 B 3/4 0-3c Associated with Amendment 219 B 3/4 0-3d Associated with Amendment 219 B 3/4 0-3e Associated with Amendment 225 B 3/4 0-3f Associated with Amendm~nt 219 B 3/4 0-4 Associated with Amendment 226 B 3/4 0-4a Associated with Amendment 226 B 3/4 0-5 169

• B 3/4 0-6 Associated with Amendment 225 B 3/4 1-1 Associated with Amendment 207 B 3/4 1-2 168 B 3/4 1-2a 178 83/41-3 186 B 3/4 1-4 Associated with Amendment 232 B3/41-5 ECR 09-00406 B 3/4 2-1 66 B 3/4 2-2 66 B 3/42-3 7 B 3/4 2-4 ECR 11-00092 B 3/4 2-5 66 B 3/4 3-1 186 B 3/4 3-1a Associated with Amendment 233 B 3/4 3-1 b Associated with Amendment 233 B 3/4 3-1c Associated with Amendment 233 B 3/4 3-1d Associated with Amendment 233 B 3/4 3-1e Associated with Amendment 233 B 3/4 3-H Associated with Amendment 233 B 3/4 3-2 186 B 3/4 3-3 186 B 3/4 3-3a Associated with Amendment 201 B 3/4 3-4 186 B 3/4 3-5 ECR LG 09-00585 B 3/4 3-5a ECR LG 09-00585 B 3/4 3-6 186 B 3/43-7 228 B 3/4 3-8 Original Issue LIMERICK - UNIT 1 . *J*

REVISED THAU AMENDMENT 233 EXCEPT IMPLEMENTATION OF AMENDMENT 227

LIMERICK GENERATING STATION UNIT 1 TECHNICAL SPECIFICATION PAGE REVISION LIST

.:)

Index Amendment Nos.

83/4 3-9 141 B 3/4 4-1 Associated with Amendment 196 B 3/44-2 Associated with Amendment 196 B 3/44-3 Associated with Amendment 208 B 3/4 4-3a Associated with Amendment 208 B 3/4 4-3b Associated with Amendment 208 B 3/4 4-3c Associated with Amendment 205 B 3/4 4-3d Associated with Amendment 205 B 3/4 4-3e Associated with Amendment 205 B 3/4 4-4 174 B 3/44-5 ECR 04-00575, Rev. 1 B 3/4 4-6 Associated with Amendment 199 B 3/4 4-6a Associated with Amendment 216 B 3/4 4-7 145 B 3/44-8 106 B 3/4 5-1 Associated with Amendment 216 B 3/4 5-2 Associated with Amendment 216 B 3/4 5-3 Associated with Amendment 216 B 3/4 5-4 Associated with Amendment 216

)

.- B 3/4 6-1 ECR 11-00395 186 .

" B 3/4 6-2 B 3/4 6-3 Associated .with Amendment 216 J B 3/4 6-3a Associated with Amendment 216 B 3/4 6-3b Associated with Amendment 216 B 3/4 6-4 186 B 3/4 6-4a 148 B 3/4 6-5 ECR LG 09-00052 B 3/4 6-5a Associated With Amendment 229 B 3/4/6-5b Associated with Amendment 229 B 3/4 6-6 1°73 B 3/4 7-1 27 B 3/4 7-1a 188 B 3/4 7-1b 188 B 3/4 7-1c Associated with Amendment 216 B 3/4 7-1d Associated with Amendment 216 B 3/4 7-2 223 B 3/4 7-3 223 B 3/4 7-4 104 B 3/4 7-5 52 B 3/4 8-1 ECR 05-00297 B 3/4 8-1a .ECR 09-00284 83/4 8-1b ECR 09-00284

~ B 3/4 8-1c 189 B 3/4 8-1d 164 B 3/4 8-1e ECR 09-00284 LIMERICK - UNIT 1 - K- REVISED THAU AMENDMENT 233 EXCEPT IMPLEMENTATION OF AMENDMENT 227

LIMERICK GENERATING STATION UNIT 1 TECHNICAL SPECIFICATION PAGE REVISION LIST Index Amendment Nos. C B 3/4 8-2 186 B 3/4 8-2a 186 B 3/4 8-2b 164 B 3/4 8-3 Associated with Amendment 209 B 3/4 9-1 4 B 3/4 9-2 ECR 06-00389 B 3/4 9-2a Associated with Amendment 216 B 3/4 9-$ Associated with Amendment 216 B 3/4 10-1 133 B 3/410-2 167 B 3/4 11-1 48 B 3/411-2 Associated with Amendment 187 B 3/4 11-3 48 B 3/411-4 *228 B 3/4 11-5 48 83/412-1 48 B 3/4 12-2 Deleted Section 5.0 Design Features 5-1 48 5-2 Original Issue 5-3 Original Issue 5-4 Original Issue 5-5 Original Issue 5-6 48 5-7 19 5-8 106 5-9 Original Issue Section 6.0 Administrative Controls 6-1 96 6-2 198 6-3 198 6-4 35 6-5 96 6-6 231 6-7 176 6-8 176 6-9 176 6-10 176 6-11 96 '

6-12 176 6-12a 176 LIMERICK - UNIT 1 -L- REVISED THRU AMENDMENT 233 EXCEPT IMPLEMENTATION OF AMENDMENT 227

LIMERICK GENERATING STATION UNIT 1 TECHNICAL SPECIFICATION PAGE REVISION LIST Index Amendment Nos.

6-13 176 6-14 166 6-14a 197 6-14b 48 6-14c 190 6-14d 223 6-t4e 228 6-15 211 6-16 211 6-17 135 6-18 48 6-18a 200 6-19 176 6-20 176 6-20a 135 6-21 135 6-21a 176 6-22 188 6-23 219 6-24 219 LIMERICK- UNIT 1 - - - M- REVISED THRU AMENDMENT 233 EXCEPT IMPLEMENTATION OF AMENDMENT 227

BASES FOR "SECTION 2. 0 SAFITT LIMITS

,, , I AND

\~

LIMITING SAFITT* SYSTEM SETTINGS

.All& 8 1985

-~ I

INTENTIONALLY LEFT BLANK I

~---------------~------------------------

The BASES contained in succeeding pages summarize tne reasons for the Specific~tions in Section 2.0,.

but in accordance with 10 CFR 50.36 are not part of these Technical Specifications.

,.IU6 8 1985

(__J

f INTENTIONALLY LEFT BLANK

2.1 SAFETY LIMITS BASES

-~----2-.Q--IN-'ffi-G98G 1'-I-GN-- - - -

The fuel cladding, reactor pressure vessel and primary system piping are the principal barriers to the release of radioactive materials to the environs. Safety Limits are established to protect the integrity of these barriers. during normal plant operations and anticipated transients. The fuel cladding integrity Safety Limit is set such that no fuel.damage is ~alculated to occur i:f the limit is not violated. Because fuel damage is not directly observable,_a step-back approach is used to establish a Safety Limit such that more than 99.9% of the fuel rods avoid transition boiling. Meeting the Safety Limit can be demonstrated by analysis that confirms less than 0.1%_of fuel rods in the core are susceptible to transition boiling or by demonstrating that the MCPR is not less than the values specified in Specification 2.1.2 for two recirculation loop operation and for single recirculation loop operation. Less than 0.1% of fuel rods in transition boiling and MCPR greater than the values specified-for two recirculation loop operation and for single recirculation loop operation represents a conservative margin relative to the conditions required to maintain fuel cladding integrity. The fuel cladding is one of the physical barriers which separate the radioactive materials from the environs. The integrity of this cladding barrier is related to its relative freedom from perforations or cracking.

Although some corrosion or use related cracking may occur during the life of the cladding, fission product migration from this source is incrementally cumulative and continuously measurable. Fuel cladding.perforations, however, can result from thermal stresses which occur from reactor operation significantly abo~v~e'--'-d~e~swi~gi.._._~~~~~~~~-

conditions and the Limiting Safety System Settings. While fission product migration from cladding perforation is just as measurable as that from use related cracking, the thepnally caused cladding perforations signal a threshold beyond which still greater thermal stresses may cause gross rather than incremental cladding deterioration. Therefore, the fuel cladding Safety Limit is defined with a margin to the conditions which would produce onset of transition boiling, MCPR of 1.0. These conditions represent a significant departure from the condition intended by design for planned operation.

2.1.1 THERMAL POWER, Low Pressure or Low Flow The use of the (GEXL) correlation is not valid for all critical power calculations at pressures below 700 psia or core flows less than 10% of rated flow. Therefore, the fuel cladding integrity Safety Limit is established by other means. This is done by establishing a limiting condition on core THERMAL POWER with the following basis. Since the pressure drop in the bypass region is *essentially all elevation head, the core pressure drop at low power and flows will always be greater than 4.5 psi. Analyses show that with a bundle flow of 28 x 10 3 lb/hr, bundle pressure drop is nearly independent of bundle power and has a value of 3.5 psi. Thus, the bundle flow with a 4.5 psi driving head will be greater than 28 x 10 3 lb/hr. Full scale ATLAS test data taken at pressures from 14.7 psia to 800 psia indicate that the fuel assembly criti-cal power at this flow is approximately 3.35 MWt. With the design peaking factors, this corresponds to a THERMAL POWER of more than 50% of RATED THERMAL POWER. Thus, a THERMAL POWER limit of 25% of RATED THERMAL POWER for reactor pressure below 700 psia is conservative.

LIMERICK - UNIT 1 B 2-1 Amendment No.+, B-, +/-H, &7-, §.-G ECR 00 00209, ECR 01 00055, +0-, ~

Associated Hith Z'.ffl:enchnent ~Jo. 206, ECR 11 00092, 222

SAFETY LIMITS 2.1.2 THERMAL POWER, H1gh Pressure and High Flow The fuel cladding integrity Safety Limit is set such that no fuel damage is calculated to occur if the limit is *not violated. Since the parameters which result in fuel damage are not directly observable during reactor operation, the thermal and hydraulic cdnditions resulting in a departure frbm nucleate boiling have been used to mark the beginning of the region where fuel damage could occur. Although it is recognized that a departure from nucleate boiling would not necessarily-;esult in damage to BWR fuel rods, the critical power at which boiling transition is calculated to occur has been adopted as a convenient limit. However, the uncertainties in monitoring the core operating state and in the procedures used to calculate the. critical power result in .an uncertainty in the value of the critical power. Therefore, the fuel cladding integrity Safety Limit is defined as the CPR in the limiting fuel assembly for which more than 99.9% of the fuel rods in the core are expected to avoid boiling transition considering the power distribution within the core and all uncertainties.

The analyses that demonstrate less than 0.1% of fuel rods enter transition boiling and determine the Safety Limit MCPR are performed using a statistical approach that combines all of the uncertainties in operating parameters and the

. procedures used to calculate critical power. The analysis methods used to perform these calculations are described in Reference 1 .

Reference:

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

LIMERICK - UNIT 1 B 2-2 Amendment No.+, ECR 11-00092

3875101020

. *,f

~--------------

LEFT INTENTIONALLY BLANK

. :v' B 2-3 Amendment No. 7- \

LIMERICK - UNIT- 1 AUS 1 4 1987

3875101020 LEFT INTENTIONALLY BLANK LIMERICt - UNIT 1 I 2-4 . Aaenmient No. 7 AUG 1 4 1987

3901000402 SAFETY LIMITS

-J----BAS-B----*

2.1.3 REACTOR COOLANT SYSTEM PRESSURE The Safety Limit for the reactor coolant system pressure has been selected such that i.t is at a pressure below which it can be shown *that the integrity of the system is not endangered. The reactor pressure vessel is designed to Section III of the ASME Boiler and Pressur* Vessel Code 1968 Edition, including Addenda through Summer 1969, which permits a maximum pres-sure transient of 110%, 1375 psig, of design pressure 1250 psig. The Safety Limit of 1325 psig, as measured by the reactor vessel steam dome pressure indicator, is equivalent to 1375 psig at the lowest elevation of the reactor coolant system. The reactor coolant system is designed to the ASME Boiler and Pressure Vessel Code, 1977 Edition, including Addenda through Summer 1977 for the reactor recirculation piping, which permits a maximum pressure transient of. 110%, 1375 psig of design pressure, 1250 psig for suction piping and 15.00 psig for discharge piping. The pressure Safety Limit is s~lected to be the lowest transient overpressure allowed by the ASME Boiler and Pressure Vessel Code Section III, Class I.

2.1.4 REACTOR VESSEL WATER LEVEL With fuel in the reactor vessel during periods when the reactor is shutdown, consideration must be given to water level requirements due to the effect of decay heat. If the water level should drop below the top of the

_.I active irradiated fuel during this period, the ability to remove decay heat is

~- \

reduced. This reduction in cooling capability could lead to elevated cladding temperatures and clad perforation in the event that the water level became less than two-thirds of the core height. The Safety Limit has been established at the top of the active irradiated fuel to provide a point which can be monitored

• and also provide adequate margin for effective action.

I,...,I LIMERICK - UNIT 1 B 2-5 OCT 3 0 1989 Amendment No. 33

2,2 LIMITING SAFETY SYSTEM SETTINGS

2. 2 .1 REACTOR PROTECTION SYSTEM INSTRUMENTATION SET POINTS The Reactor Protection System instruTl)entation setpoints spe~ified in Table. 2.2.1-1 are the values at which the reactor trips are set for each para-meter. The Tr~p Setpoints have been selected to ensure that the reactor core and reactor coolant system are prevented from exceeding their Safety Limits during normal operation and design basis anticipated operational occurrences.

and to assist in mitigating the consequences of accidents. Operation with a trip set less conservitive than its Trip Setpoint but within its specified Allowable Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is equal to or less than the drift allowance assumed for each trip in the safety analyses.

1. Intermediate Range Monitor. Neutron Flux - High The !RM system'consists of 8 chambers, 4 in each of the reactor trip systems. The IRM is a 5 decade 10 range instrument. The trip setpoint of 120 divisions of scale is active in each of the 10 ranges. Thus as the IRM is ranged up to accommodate the increase in power level, the trip setpoint is also ranged up. The IRM instruments provide for overlap with both the APRM and SRM systems.

The most significant source of reactivity changes during the power increase is due to control rod withdrawal. In order to ensure that the IRM provides the required protection, a range of rod withdrawal accidents have been analyzed. The results of these analyses are in Section 15.4 of the FSAR. The most severe case involves an initial condition in which THERMAL POWER is at approximately 1% of RATED THERMAL POWER. Additional conservatism was taken in this analysis by assuming the !RM channel closest to the control rod bein~ withdrawn is bypassed. The results of this analysis show that the reactor 1s shutdown and peak power is limited to 21% of RATED THERMAL POWER with the peak fuel enthalpy well below the fuel failure threshold of 170 cal/gm.

Based on this analysis, the !RM provides protection against local control rod errors and continuous withdrawal of control rods in sequence and provides backup

• protection for the APRM.

2. Average Power Range Monitor The APRM system is divided into four APRM channels and four 2-0ut-Of-4 Voter channels. The four voter channels are divided into two groups of-two each, with each group of two providing inputs to one RPS trip system. All four voters wi 11 trip (full scram) when any two unbypassed APRM channels exceed their trip setpoints.

APRM trip Functions 2.a, 2.b, 2.c, and 2.d are voted independently from OPRM Upscale Function 2.f. Therefore, any Function 2.a, 2.b, 2.c, or 2.d trip from any two unbypassed APRM channels will result in a full trip 1n each of the four voter channels. Similarly, a Function 2.f trip from any two unbypassed APRM channels will result in a full trip from each of the four voter channels.

For operation at low pressure and low flow during STARTUP the APRM Neutron Flux-Upscale (Setdown) scram setting of 15% of RATED THERMAL *p6wrn provides adequate thermal margin between the setpoint and the Safety Limits. The margin accommodates the anticipated maneuvers associated with power plant startup. Effects of increasing pressure at zero or low void content are minor and cold water from sources available during startup is not much colder than that already in the system. Tempera-ture coefficients are small a~d control rod patterns are constrained by the RWM. Of all the possible sources of reactivity input, uniform control rod withdrawal is the most probable cause of significant power increase. ~

LIMERICK - UNIT 1 B 2-6 Amendment No. J-7., .JA.l, 177

LIMITING SAFETY SYSTEM SETTINGS REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS (Continued)

Average Power Range Monitor (Continued)

Because the* flux distribution associated with uniform rod withdrawals does.not involve high local peaks and because several rods must be moved to change power by a significant amount, the rate of power rise is very slow. Generally the heat flux is in near equilibrium with the fission rate. In an assumed uniform rod withdrawal approach to the trip level, the rate of power rise is not more than 5% of RATED THERMAL POWER per minute and the APRM system would be more than adequate to assure shutdown*before the power coul~ exceed the Safety Limit.

The 15% Neutron Flux - Upscale (Setdown) trip remains active until the mode switch is placed in the Run position.

The APRM trip system is calibrated using heat balance data taken during steady state conditions. Fission chambers provide the basic input to the system and therefore the monitors respond directly and quickly to changes due to transient operation for the case of the Neutron Flux - Upscale setpoint; i.e.,

for a power increase, the THERMAL POWER of the fuel will be less than that indicated by the neutron flux due to the time constants of the heat transfer associated with the fuel. For the Simulated Thermal Power - Upscale setpoint, a time constant of 6 +/- 0.6 seconds is introduced into the flow-biased APRM in order to simulate the fuel thermal transient ~haracteris tics. A more conservative maximum.value is used for the flow-biased setpoint as shown in Table 2.2.1-1.

A reduced Trip S~tpoint and Allowable Value is provided for th~ Simulated Thermal Power - Upscale Function, applicable when the plant is operating in Single Loop Operation (SLO) per LCO 3.4.1.1. In SLO, the drive flow values (W) used in the Trip Setpoint and Allowable Value equations is reduced by 7.6%. The 7.6% value is established to conservatively bound the inaccuracy created in the core flow/drive flow correlation due to back flow in the jet pumps associated with the inactive recirculatio n loop. The Trip Setpoint and Allowable Value thus maintain thermal margins essentially unchanged from those for two-loop. operation.

The Trip Setpoint and Allowable Value equations for single loop operation are only valid for flows down to W= 7.6%. The Trip Setpoint and Allowable Value do not go below 61.5% and 62.0% RATED THERMAL POWER, respectively . This is acceptable because back flow in the inactive recirculatio n loop is only an issue with drive flows of approximately 40% or greater (Reference 1) ..

The APRM setpoints were selected to provide adequate margin for the Safety Limits and yet allow operating margin that reduces the possibility of unneces-sary shutdown.

The APRM channels also include an Oscillation Power Range Monitor (OPRM) Upscale *Function. The OPRM Upscale Function provides compliance with GDC 10 and GDC 12, thereby providing protection from exceeding the fuel MCPR Safety Limit due to anticipated thermal-hyd raulic power oscillation s. The OPRM Upscale Function receives input signals from the local power range monitors (LPRMs) within the reactor core, which are combined into "cells>> for evaluation by the OPRM algorithms.

• References 2, 3 and 4 describe three algorithms for detecting thermal-hydraulic instability related neutron flux oscillations : the period based detection algorithm, the amplitude based algorithm, and the growth rate algorithm. All t~ree are implemented in the OPRM Upscale Function, but the safety analysis takes credit only for the period based detection algorithm. The remaining algorithms provide defense in depth and additional protection against unanticipated oscillations . OPRM Upscale Function OPERABILITY for Technical Specificatio n purposes is based only on the period based detection algorithm.

LIMERICK - UNIT 1 B 2-7 Amendment No. e-&,+4+/-,-+/--7-7-,

Associated with Amendment 201

LIMITING SAFETY SYSTEM SETTINGS REACTOR PROTECTION ?YSTEM INSTRUMENTATION SETPOINTS (Continued)

Average Power Range Monitor (Continued)

The OPRM Upscale trip output shall be automatically enabled (not bypassed) when APRM Simulated Thermal Power is~ 29.5% and recirculation drive flow is< 60%

as indicated by APRM measured recirculation drive flow. (NOTE: 60% recirculation drive flow is the recirculation drive flow that corresponds to 60% of rated core flow. Refer to TS Bases 3/4.3.1 for further discussion concerning the recirculation drive flow/core flow relationship.) This is the operating region where actual thermal-hydraulic instability and related neutron flux oscillations may occur. See Reference 5 for additional discussion of OPRM Upscale trip enable region limits. These setpoints, which are sometimes referred to as the "auto-bypass" setpoints, establish the boundaries of the OPRM Upscale trip enabled region. The APRM Simulated Thermal Power auto-enable setpoint has 1% deadband while the drive flow setpoint has a 2% deadband. The deadband for these setpoints is established so that it increases the enabled region.

An OPRM Upscale trip is issued from an APRM channel when the period based detection algorithm in that channel detects oscillatory changes in the neutron flux, indicated by the combined signals of the LPRM detectors in a cell, with period confirmations and relative cell amplitude exceeding specified setpoints.

One or more cells in a channel exceeding the trip conditions will result in a channel trip. An OPRM Upscale trip is also issued from the channel if either the growth rate or amplitude based algorithms detect oscillatory changes in the neutron flux for one or more cells in that channel.

There are four "sets" of OPRM related setpoints or adjustment parameters:

a) OPRM trip auto-enable setpoints for APRM Simulated Thermal Power (29.5%) and (-*-

recirculation drive flow (60%); b) period based detection algorithm (PBDA) confirmation count and amplitude setpoints; c) period based detection algorithm

,1(

tuning parameters; and d) growth rate algorithm (GRA) and amplitude based algorithm (ABA) setpoints.

The first set, the OPRM auto-enable region setpoints, are treated as nominal setpoints with no additional margins added as discussed in Reference 5.

The settings, 29.5% APRM Simulated Thermal Power and 60% recirculation drive flow, are defined (limit values) in a note to Table 2.2.1-1. The seco.nd set, the OPRM PBDA trip setpoints, are established in accordance with methodologies defined in Reference 4, and are documented in the COLR. There are no allowable values for these setpoints. The third set, the OPRM PBDA "tuning" parameters, are established or adjusted in accordance with and controlled by station procedures.

The fourth set, the GRA and ABA setpoints, in accordance with References 2 and 3, are established as nominal values only, and controlled by station procedures.

3. Reactor Vessel Steam Dome Pressure-High High pressure in the nuclear system could cause a rupture to the nuclear system process barrier resulting in the release of fission products. A pressure increase while operating will also tend to increase the power of the reactor by compressing voids thus adding reactivity. The trip will quickly reduce the neutron flux, counteracting the pressure increase. The trip setting is slightly higher than the operating pressure to permit normal operation without spurious trips. The setting provides for a wide margin to the maximum allowable design pressure and takes into account the location of the pressure measurement compared to the highest pressure that occurs in the system during a transient. This trip setpoint is effective at low power/flow conditions when the turbine stop valve and control fast closure trips are bypassed. For a turbine trip or load rejection under these conditions, the transient analysis indicated an adequate margin to 1

• -C the thermal hydraulic limit.

LIMERICK - UNIT 1 B 2-7a Amendment No. iG,~,++-7.

Associated with Amendment 201

---

J--

INTENTIONALLY LEFT BLANK

LIMITING SAFETY SYSTEM SETTINGS BASES REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS (Continued)

4. Reactor Vessel Water Level-Low The reactor vessel water level tri~ setpoint has been used in transient analyses dealing with coolant inventory i:lecrease. The scram setting was chosen.

far enough below the normal operating level to avoid spurious trips butthehigh fuel enough above the fuel to assure that there is adequate protection for and pressure limits.

5. Main Steam Line Isolation Valve-Closure The main steam line isolation valve closure trip was ~rovided to limit the amount of fission product release for certain postulatei:I events. The MSIVs are closed automatically from measured parameters such as high steam flow, low reactor water level, high steam tunnel temperature, and low steam line pressure.

The MSIVs closure scram anticipates the pressure and flux transients which could follow MSIV closure and thereby protects reactor vessel pressure and fuel thermal/hydraulic Safety Limits.

6. DELETED

7. QrvweJJ Pressure-High High pressure in the drywell could indicate a break in the primary pressure boundary systems or a loss of drywell cooling. The reactor is tri~ped in order to minimize the possibility of fuel damage and reduce the amount of energy being added to the coolant and to the primary containment. The trip setting was selected as low as possible without causing spurious trips.

• FD 1 6 1995 .

LIMERICK - UNIT 1 B 2-8 Amerxlment No. 89

LIMITING SAFETY SYSTEM SETTING

_"'-',___)- - - - -

BASES REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS (Continued)

8. Scram Discharge Volume Water Level-High The scram discharge volume receives the water displaced.by the:motion of the control rod drive pistons during a reactor scram.. Should this v.olume fill up to a point-where*the re is insufficie*nt volume to accept the displaced water

- at pressures -below 65 _psig, control rod insertion would be hindered.'. The reactor is therefore tripped whe!'l th_e water level has reached a point high enough to indicate that it is indeed filling up, but the volume is still gre~t enough to accommodate. the water from the movement of the* rods at pressures below 65 psi*g when they are. tripped~ The trip setpoint for each scram discharge volume is equivalent to*.a contained volume of 25.45 gallons of water.

9. Turbine ~top Valve-Closure The turbine stop valve closure trip anticipates the pressure, neutron f.lux, and heat flux increases that would result fr.om closure of the stop valves. With.'a trip setting of 5% of valve c~osure from full *open, the resultant increase in heat flux is such that adequate*thermal margins are maintained during the worst design basis transient.

• ~ lO. Turbine Control Valve Fast Closure, Trip Oil Pressure-Low The turbine control valve fast closure*trip anticipates the pressure, neutron flux, and heat flux increase that could result from fast closure of the turbine control valves due to load rejection with.or without coincident failure of. the turbine bypass valves. The Reactor Protection System initiates a trip when fast closure of the control valves is initiated by the fast acting solenoid valves and in less than 30 milliseconds after the start of control valve fast closure. This is achieved by the action of the fast acting solenoid valves in rapidly reducing

• hydraulic trip oil pressure at the main turbine control valve actuator disc dump valves. This loss of pressur~ is sensed by pressure swjtches whose contacts form the one-out-of-two- twice logic input to the Reactor Protection System. This trip setting, a faster clos~re time, and a different valve characteristic from that of the turbine stop valve, combine to produce transients which are very similar to that for the stop valve. Relevant transient analyses are discussed "in Section 15.2.2 of the Final Safety Analysis Report.

11. Reactor Mode Switch Shutdown Position The reactor mode* switch Shutdown position is a redundant channel to the automatic protective instrumentation channe~s and provid~s additional manual reactor trip capability.

12. Manual Scram The Manual Scram* is a redundant channel to the automatic protective*

instrumentation channels and provides man*ual reactor trip capability .

LIMERICK - UNIT 1 B 2-9 .NJ6 8 1935

LIMITING SAFETY SYSTEM SETTINGS REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS (Continued)

REFERENCES:

1. NEDC-31300, "Single-Loop Operation Analysis for Limerick Generating Station, Unit l," August 1986.

2.

• NED0-31960-A, "BWR O~ners'. Group Long-Term Stability. Solutions

/ Licensing Methodology," November 1995.'

3. NED0-31960-A, Supplement 1, "BWR Owners' Group Long-Term Stability Solutions Licensing Methodology," November 1995.

4. NED0-32465-A, "Reactor Stability Detect and Suppress Solutions Licensing Basis Methodology fqr Reload App1ications," August 1996.

5. BWROG Letter 96113, K. P. Donovan (BWROG) to L. E. Phillips (NRC),

"Guide.lines for Stability Option III 'Enable Region' (TAC M92882),"

September 17, 1996.

<(_

LIMERICK - UNIT 1 B 2-10 Amendment No. 177 I

)

BASES FOR SECTIONS 3. 0 AND 4. 0 .

LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS AUG 8 .1985

INTENTIONALLY LEFT BLANK NOTE The BASES contained in succeeding pages summarize the reasons for the Specifications in Sections 3.0 and 4.0, but in accordance with 10 CFR 50.36 are not part of these Technical Specifications.

AUG B 1985

3890020620 THIS PAGE INTENTIONALLY LEFT BLANK

3/4.0 APPLICABILITY B SES

.:) Specifications 3.0.1 through 3.0.4 establish the general requirements applicable to Limiting Conditions for Operation. These requirements are based on the requirements for Limiting Conditions for Operation stated in the Code of Federal Regulations, 10 CFR 50.36(c)(2):

"Limiting Conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When a limiting condition for operation of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specification until the condition can be met."

Specification 3.0.1 establishes the Applicability statement within each individual specification as the requirement for when (i.e., in which OPERATIONAL CONDITIONS or other specified conditions) conformance to the Limiting Conditions for Operation is required for safe operation of the facility. The ACTION requfrements establish those remedial measures that must be taken within specified time limits when the requirements of a Limiting Condition for Operation are not met. It is not intended that the shutdown ACTION requirement be used as an operational convenience which permits (routine) voluntary removal of a system(s) or component(s) from service in lieu of other alternatives that would not result in redundant systems or components being inoperable.

There are two basic types of ACTION requirements. The first specifies the remedial measures that permit continued operation of the facility which is not further restricted by the time limits of the ACTION requirements. In this case, conformance to the ACTION requirements provides an acceptable level of safety for unlimited continued operation as long as the ACTION requirements continue to be met. The second type of ACTION requirement specifies a time limit in which conformance to the conditions of the Limiting Condition for Operation must be met. This time limit is the allowable outage time to restore an inoperable system or component to OPERABLE status or for restoring parameters within specified limits. If these actions are not completed within

.the allowable outage time limits, a shutdown is required to place the facility irt an OPERATIONAL CONDITION or other specified condition in which the specifi-cation no longer applies.

The specified time limits of the ACTION requirements are applicable from the point of time it is identified that a Limiting Condition for Operation is not met. The time limits of the ACTION requirements are also applicable when' a system or component is removed from service for surveillance testing or investigation of operational problems. Individual specifications may include a specified time limit for the completion of a Surveillance Requirement when equipment is removed from service. In this case, the allowable outage time limits of the ACTION requirements are applicable when this limit expires if the surveillance has not been completed. When a shutdown is required to comply with ACTION requirements, the plant may have entered an OPERATIONAL CONDITION in which a new specification becomes applicable. In this case, the time limits of the ACTION requirements would apply from the point in time that the new specification becomes applicable if the requirements of the Limiting Condition for Operation are not met.

LIMERICK - UNIT 1 B 3/4 0-1 Amendment No . 11 I

3/4.0 APPLICABILITY Specification 3.0.2 establishes that noncompliance with a specification exists when the requirements of the Limiting Condition for Operation are not met and the associated ACTION requirements have not been implemented within the specified time interval, unless otherwise specified.* The purpose of this specification is to clarify that (1) implementation of the ACTION requirements within the specified time inter-val constitutes compliance with a specification and (2) completion of the remedial measures of the ACTION requirements is not required when compliance with a Limiting Condition of Operation is restored within the time interval specified in the associated ACTION requirements.

Specification 3.0.3 establishes the shutdown ACTION requirements that must be implemented when a Limiting Condition for Operation is not met and the condition is not specifically addressed by the associated ACTION requirements. The purpose of this specification is to delineate the time limits for placing the unit in a safe shutdown CONDITION when plant operation cannot be maintained within the limits for safe operation defined by the Limiting Conditions for Operation and its ACTION requirements. It is not intended to be used as an operational convenience which permits (routine) voluntary removal of redundant systems or components from service in lieu of other alternatives that would not result in redundant systems or components being inoperable. One hour is allowed to prepare for an orderly shutdown before initiating a change in plant operation. This time permits the operator to coordinate the reduction in electrical generation with the load dispatcher to ensure the stability and availability of the electrical grid. The time limits specified to enter lower CONDITIONS of operation permit the shutdown to proceed in a controlled and orderly manner that is well*within the specified maximum cooldown rate and within the cooldown capabilities of the facility assuming only the minimum required equipment is OPERABLE. This reduces thermal stresses on components of the primary coolant system and the potential for a plant upset that could challenge safety systems under conditions for which this specification applies.

If remedial measures permitting limited continued operation of the facility under the provisions of the ACTION requirements are completed, the shutdown may be terminated. The time limits of the ACTION requirements are applicable from the point in time there was a failure to meet a Limiting Condition for Operation. Therefore, the shutdown may be terminated if the ACTION require-ments have been met, the ACTION is no longer applicable, or time limits of the ACTION requirements have not expired, thus providing an allowance for the completion of the required actions.

The time limits of Specification 3.0.3 allow 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br /> for the plant to be in COLD SHUTDOWN when a shutdown is required during POWER operation. If the plant is in a lower CONDITION of operation when a shutdown is required, the time limit for entering the next lower CONDITION of operation applies. However, if a lower CONDITION of operation is entered in less time than allowed, the total allowable time to enter COLD SHUTDOWN, or other OPERATIONAL CONDITION, is not reduced. For example, if STARTUP is entered in 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, the time allowed to enter HOT SHUTDOWN is the next 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> because the total time to enter HOT SHUTDOWN is not reduced from the allowable limit of 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />. Therefore, if remedial measures are completed that would permit a return to POWER operation, a penalty is not incurred by having to enter a lower CONDITION of operation in less than the total time allowed.

LIMERICK - UNIT 1 B 3/4 0-2 Amendment No. ii, Associated with Amendment No. 226

3/4.0 APPLICABILITY BASES

) The same principle applies with regard to the allowable outage time limits of the ACTION requirements, if compliance with the ACfION requirements for one specificat ion results in entry into an OPERATIONAL CONDITION or condition of operation for another specificat ion in which the requirements of the Limiting Condition for Operation are not met. If the new specifica tion becomes appli-cable in less time than specified, the difference may be added to the allowable outage time limits of the second specificat ion. However, the allowable outage time limits of ACfION requirements for a higher CONDITION of operation may not be used to extend the allowable outage time that is applicable when a Limiting Condition for Operation is not met in a lower CONDITION of operation.

The shutdown requirements of Specificat ion 3.0.3 do not apply in CONDITIONS 4 and 5, because the ACfION requirements of individual specificat ions define the remedial measures to be taken ..

Specifica tion 3.0.4 establishe s limitation s on changes in OPERATIONAL CONDITIONS or other specified condition s in the Applicabi lity when a Limiting Condition for Operation is not met. It allows placing the unit in an OPERATIONAL CONDITION or other specified condition stated in that Applicabi lity (e.g., the Applicab ility desired to be entered) when unit conditions are such that the requirements of the Limiting Condition for Operation would not be met, in accordance with either Specifica tion 3.0.4.a, Specificat ion 3.0.4.b, or Specifica tion 3.0.4.c.

Specifica tion 3.0.4.a allows entry into an OPERATIONAL CONDITION or other specified condition in the Applicabi lity with the Limiting Condition for Operation not met when the associated ACTION requirements to be entered following entry into the OPERATIONAL CONDITION or other specified condition in the Applicabi lity will permit continued operation within the MODE or other specified condition for an unlimited period of time. Compliance wi~h ACTIONS that permit continued operation of the unit for an unlimited period of time in an OPERATIONAL CONDITION or other specified condition provides an acceptable level of safety for continued operation . This is without regard to the status of the unit before or after the OPERATIONAL CONDITION change. Therefore, in such cases, entry into an OPERATIONAL CONDITION or other specified condition in the Applicabi lity may be made and the Required Actions followed after entry into the Applicabi lity.

For example, LCO 3.0.4.a may be used when the Required Action to be entered states that an inoperabl e instrument channel must be placed in the trip condition within the Completion Time. Transition into a MODE or other specified condition in the Applicabi lity may be made in accordance with LCO 3.0.4 and the channel is subsequently placed in the tripped condition within the Completion Time, which begins when the Applicab ility is entered. If the instrument channel cannot be placed in the tripped condition and the subsequent default ACTION ("Required Action and associated Completion Time not met") allows the OPERABLE train to be placed in operation , use of LCD 3.0.4.a is acceptable because the subsequent ACTIONS to be entered following entry into the MODE include ACTIONS (place the OPERABLE train in operation ) that permit safe plant operation for an unlimited period of time in the MODE or other specified condition to be entered.

Specifica tion 3.0.4.b allows entry into an OPERATIONAL CONDITION or other specified condition in the Applicabi lity with the Limiting Condition for Operation not met after performance of a risk assessment addressing inoperable systems and components, consideration of.the results, determination of the acceptabi lity of enteiing the OPERATIONAL CONDITION or other specified condition in the Applicab ility, and establishment of risk management actions, if appropria te.

LIMERICK - UNIT 1 B 3/4 0-3 Amendment No. li, ~ . -169, Associated with Amendment No. 226

3/4.0 APPLICABILITY The risk assessment may use quantitative, qualitative, or blended approaches, and ~-

the risk assessment will be conducted using the plant program, procedures, and \._

criteria in place to implement 10 CFR 50.65(a)(4), which requires that risk impacts of maintenance activities be assessed and managed. The risk assessment, for the purposes of Specification 3.0.4.b, must take into account all inoperable Technical Specification equipment regardless of whether the equipment is included in the normal 10 CFR 50.65(a)(4) risk assessment scope. The risk assessments will be conducted using the procedures and guidance endorsed by Regulatory Guide 1.182, "Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants." Regulatory Guide 1.182 endorses the guidance in Section 11 of NUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants." These documents address general guidance for conduct of the risk assessment, quantitative and qualitative guidelines for establishing risk management actions, and example risk management actions. These include actions to plan and conduct other activities in a manner that controls overall risk, increased risk awareness by shift and management personnel, actions to reduce the duration of the condition, actions to minimize the magnitude of risk increases (establishment of backup success paths or compensatory measures), and determination that the proposed OPERATIONAL CONDITION change is acceptable.

Consideration should also be given to the probability of completing restoration such that the requirements of the Limiting Condition for Operation would be met prior to the expiration of the ACTION requirement's specified time interval that would require exiting the Applicability.

Specification 3.0.4.b may be used with single, or multiple systems and components unavailable. NUMARC 93-01 provides guidance relative to consideration of simultaneous unavailability of multiple systems and components.

The results of the risk assessment shall be considered in determining the acceptability of entering the OPERATIONAL CONDITION or other specified condition in the Applicability, and any corresponding risk management actions. The Specification 3.0.4.b risk assessments do not have to be documented.

The Technical Specifications allow continued operation with equipment unavailable in OPERATIONAL CONDITION 1 for the duration of the specified time interval.

Since this is allowable, and since in general the risk impact in that particular OPERATIONAL CONDITION bounds the risk of transitioning into and through the applicable OPERATIONAL CONDITIONS or other specified conditions in the Applicability of the Limiting Condition for Operation, the use of the Specification 3.0.4.b allowance should be generally acceptable, as long as the risk is assessed and managed as stated above. However, there is a small subset of systems and components that have been determined to be more important to risk and use of the Specification 3.0.4.b allowance is prohibited. The Limiting Condition for Operations governing these system and components contain Notes prohibiting the use of Specification 3.0.4.b by stating that Specification 3.0.4.b is not applicable.

Specification 3.0.4.c allows entry into a OPERATIONAL CONDITION or other specified condition in the Applicability with the Limiting Condition for Operation not met based on a Note in the Specification which states Specification 3.0.4.c is applicable. These specific allowances permit entry into OPERATIONAL CONDITIONS or other specified conditions in the Applicability when the associated ACTION requirements to be entered do not provide for continued operation for an unlimited period of time and a risk assessment has not been performed. This allowance may apply to all the ACTION requirements or to a specific ACTION r quirement of a Specification. The risk assessments performed to justify the 1 use of c_*

Specification 3.0.4.b usually only consider systems and components. For this LIMERICK - UNIT 1 B 3/4 0-3a Amendment No.~. i6r, :l:69, Associated with Amendment No. 226

3/4.0 APPLICABILITY B SES

.)

reason, Specification 3.0.4.c is typically applied to Specifications which describe values and parameters (e.g., Reactor Coolant Specific Activity), and may be applied to other Specifications based on NRC plant-specific approval.

The provisions of this Specification should not be interpreted as endorsing the failure to exercise the good practice of restoring systems or components to OPERABLE status before entering an associated OPERATIONAL CONDITION or other specified condition in the Applicability.

The provisions of Specification 3.0.4 shall not prevent changes in OPERATIONAL CONDITIONS or other specified conditions in the Applicability that are required to comply with ACTION requirements. In addition, the provisions of Specification 3.0.4 shall not prevent changes in OPERATIONAL CONDITIONS or other specified

__J LIMERICK - UNIT 1 B 3/4 0-3al Amendment No. H:, fe, 16-9, Associated with Amendment No. 226

C INTENTIONALLY LEFT BLANK c.*

3/4.0 APPLICABIL!lY BASES

) conditions in the Applicabilit y that result from any unit shutdown. In this context, a unit shutdown is defined as a change in OPERATIONAL CONDITION or other specified condition in the Applicabilit y associated with transitionin g from OPERATIONAL CONDITION 1 to OP.ERATIONAL CONDITION 2, OPERATIONAL CONDITION 2 to OPERATIONAL CONDITION 3, and OPERATIONAL CONDITION 3 to OPERATIONAL CONDITION 4.

Upon entry into an OPERATIONAL CONDITION or other specified condition in the Applicabili ty with the Limiting Condition for Operation not met, Specificatio n 3.0.1 and Specificatio n 3.0.2 require entry into the applicable Conditions and

• ACTION requirements until the Condition is resolved, until the Limiting Condition for Operation is met, or until the unit is not within the Applicabilit y of the Technical Specificatio n.

Surveillance s do not have to be performed on the associated inoperable equipment (or on variables outside the specified limits), as permitted by Specificatio n 4.0.1. Therefore, utilizing Specificatio n 3.0.4 is not a violation of Specificatio n 4.0.1 or Specificatio n 4.0.4 for any Surveillance s that have not*

been performed on inoperable equipment. However, SRs must be met to ensure OPERABILITY prior *to declaring the associated equipment OPERABLE (or variable within limits) and restoring compliance with the affected Limiting Condition for Operation.

Specificatio n 3.0*.5 establishes the allowance for restoring equipment to service under administrati ve controls when it has been removed from ~ervice or declared inoperable to comply with ACTIONs. The sole purpose of this Specificatio n is to provide an exception to Specificatio ns 3. 0 .1 and 3*. 0. 2 (e.g. , to not comp 1y with the applicable ACTION(s)) to allow the performance of required testing to demonstrate:

a,. The OPERABILITY of the equipment being returned to service, or

b. The OPERABILITY of other equipment.

The administrati ve controls ensure the time the equipment is returned to service in conflict with the requirements of the ACTIONs is limited to the time necessary to perform the required testfog to demonstrate OPERABILITY. This Specificatio n does not provide time to perform any other preventive or corrective maintenance.

LCO 3.0.5 should not b~ used in lieu of other practicable alternatives that comply with Required Actions and that do not require changing the MODE or other specified conditions in the Applicabilit y in order to demonstrate equipment is OPERABLE.

LCO 3.0.5 is not intended to be used repeatedly.

An example of demonstrating equipment is OPERABLE with the Required Actions not met is opening a manual valve that was closed to comply with Required Actions to isolate a flowpath with excessive Reactor Coolant System (RCS) Pressure Isolation Valve (PIV) leakage in order to perform testing to demonstrate that RCS PIV leakage is now within limit.

LIMERICK - UNIT 1 B 3/4 0-3b Amendment No. :1+/-,3:6-r,~,

Associated with Amendment No. 226

3/4.0 APPLICABILITY Examples of demonstrating equipment OPERABILITY include instances in which it is necessary to take an inoperable channel or trip system out of a tripped condition that was directed by a Required Action, if there is no Required.Action Note for C

this purpose. An example of verifying OPERABILITY of equipment removed from service is taking a tripped channel out of the tripped condition to permit the logic to function and indicate the appropriate response during performance of required testing on the inoperable channel.

Examples of demonstrating the OPERABILITY of other equipment are taking an inoperable channel or trip system out of the tripped condition 1) to prevent the trip function from occurring during the performance of required testing on another channel in the other trip system, or 2) to permit the logic to function and indicate the appropriate response during the performance of required testing on another channel in the same trip system.

The administrative controls in LCO 3.0.5 apply in all cases to systems or components in Chapter 3 of the Technical Specifications, as long as the testing could not be conducted while complying with the Required Actions. This includes the realignment or repositioning of redundant or alternate equipment or trains previously manipulated to comply with ACTIONS, as well as equipment removed from service or declared inoperable to comply with ACTIONS.

LIMERICK - UNIT 1 B 3/4 0-3bl Amendment No. i:l,~,-3:69, Associated with Amendment No. 226

3/4.0 APPLICABILITY Specification 3.0.6 establishes an exception to Specifications 3.0.1 and 3.0.2 for supported systems that have a support system Limiting Condition for Operation specified in the Technical Specifications (TS). The exception to Specification C

3.0.1 is provided because Specification 3.0.1 would require that the ACTIONs of the associated inoperable supported system Limiting Condition for Operation be entered solely due to the inoperability of the support system. This exception is justified because the actions that are required to ensure the plant is maintained in a safe condition are specified in the support system Limiting Condition for Operation's ACTIONs. These ACTIONs may include entering the supported system's ACTIONs or may specify other ACTIONs. The exception to Specification 3.0.2 is provided because Specification 3.0.2 would consider not entering into the ACTIONs for the supported system within the specified time intervals as a TS noncompliance.

When a support system is inoperable and there is a Limiting Condition for Operation specified for it in the TS, the supported system(s) are required to be declared inoperable if determined to be inoperable as a result of the support system inoperability. However, it is not necessary to enter into the supported systems' ACTIONs unless directed to do so by the support system's ACTIONs. The potential confusion and inconsistency of requirements related to the entry into multiple support and supported systems' Limiting Condition for Operations' 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 ACTIONs.

However, there are instances where a support system's ACTION may either direct a supported system to be declared inoperable or direct entry into ACTIONS for the supported system. This may occur immediately or after some specified delay to perform some other ACTION. Regardless of whether it is immediate or after some delay, when a support system's ACTION directs a supported system to be declared C

inoperable or directs entry into ACTIONs for a supported system, the applicable ACTIONs shall be entered in accordance with Specification 3.0.1.

Specification 6.17, "Safety Function Determination Program (SFDP)," ensures loss of safety function is detected and appropriate actions are taken. Upon entry into Specification 3.0.6, 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 ACTIONs.

The SFDP implements the requirements of Specification 3.0.6.

The following examples use Figure B 3.0-1 to illustrate loss of safety function conditions that may result when a TS support system is inoperable. In this figure, the fifteen systems that comprise Train A are independent and redundant to the fifteen systems that comprise Train B. To correctly use the figure to illustrate the SFDP provisions for a cross train check, the figure establishes a relationship between support and supported systems as follows: the figure shows System 1 as a support system for System 2 and System 3; System 2 as a support system for System 4 and System 5; and System 4 as~ support system for System 8 and System 9. Specifically, a loss of safety function may exist when a support system is inoperable and:

a. A system redundant to system(s) supported by the inoperable support system is also inoperable (EXAMPLE B 3.0.6-1),

LIMERICK - UNIT 1 B 3/4 0-3c Associated with Amendment No. 219

3/4.0 APPLICABILITY BAE

- ,-,,____~- .u-b--""A-sy..s.tenL.r..e.dun.d.a.nLtD.-s,y_si.enl-(..s.)_j...l'.l---+/-.u.)2.l'.l-S.U.pf)-G-l'.'.te...d-...b-Y-Ul----:i--l+G.p--r-a-l:J:J..e,______ - - - - -

-. ____/

supported system is also inoperable (EXAMPLE B 3.0.6-2), or

c. A system redundant to support system(s) for the supported systems (a) and (b) above is also inoperable (EXAMPLE B 3.0.6-3).

For the following examples, refer to Figure B 3.0-1.

EXAMPLE B 3.0.6-1 If System 2 of Train A is inoperable and System 5 of Train Bis inoperable, a loss of safety function exists in Systems 5, 10, and 11.

EXAMPLE B 3.0.6 If System 2 of Train A is inoperable, and System 11 of Train Bis inoperable, a loss of safety function exists in System 11.

EXAMPLE B 3.0.6-3 If System 2 of Train A is inoperable, and System 1 of Train Bis inoperable, a loss of safety function exists in Systems 2, 4, 5, 8, 9, 10 and 11 .

I. . -,

TRAINA .IB8.!!:!..§ 1-m* System 4 System 4

-System 9 System 9 I. . .m,.

system 2 System 2 System 5 I """m" System 5 System 11 System 11 I I System 1 System 1 S,,,<om" ""m" Systems System 6 System 13 System 13 System 3 System 3 System 7 I ""'"m" System 7 I ""m" System 15 System 15 Figure B 3.0-1 Configuration of Trains and Systems If an evaluation determines that a loss of safety function exists, the appropriate ACTIONs of the Limiting Condition for Operation in which the loss of safety function exists are required to be entered. This loss of safety function does not require the assumption of additional single failures or loss of offsite power.

Since operations are being restricted in accordance with the ACTIONs of the support system, any resulting temporary loss of redundancy or single failur~

protection is taken into account.

LIMERICK - UNIT 1 B 3/4 0-3d Associated with Amendment No. 219

3/4.0 APPLICABILITY When loss of safety function is determined to exist, and the SFDP requires entry into the appropriate ACTIONs of the Limiting Condition for Operation in which the loss of safety function exists, consideration must be given to the specific type of function affected. Where a loss of function is solely due to a single Technical Specification support system (e.g., loss of automatic start due to inoperable instrumentation, or loss of pump suction source due to low tank level),

the appropriate Limiting Condition for Operation is the Limiting Condition for Operation for the support system. The ACTIONs for a support system Limiting Condition for Operation adequately address the inoperabilities of that system without reliance on entering its supported system Limiting Condition for Operation. When the loss of function is the result of multiple support systems, the appropriate Limiting Condition for Operation is the Limiting Condition for Operation for the supported system.

Specification 4.0.1 through 4.0.S establish the general requirements applicable to Surveillance Requirements. SR 4.0.2 and SR 4.0.3 apply in Section 6, Administrative Controls, only when invoked by a Section 6 Specification. These requirements are based on the Surveillance Requirements stated in the Code of Federal Regulations 10 CFR S0.36(c)(3):

"Surveillance requirements are requirements relating to test, calibration, or inspection to ensure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions of operation will be met."

Specification 4.0.1 establishes the requirement that SRs must be met during the ((~~;_,

OPERATIONAL CONDITIONS or other specified conditions in the Applicability for which the requirements of the Limiting Condition for Operation apply, unless otherwise specified in the individual SRs. This Specification is to ensure that Surveillances are performed to verify the OPERABILITY of systems and components, and that variables are within specified limits. Failure to meet a Surveillance within the specified Surveillance time interval and allowed extension, in accordance with Specification 4.0.2, constitutes a failure to meet the Limiting Condition for Operation.

Systems and components are assumed to be OPERABLE when the associated SRs have been met. Nothing in this Specification, however, is to be construed as implying that systems or components are OPERABLE when:

a. The systems or components are known to be* inoperable, although still meeting the SRs; or

b. The requirements of the Surveillance(s) are known to be not met between required Surveillance performances.

Surveillances do not have to be performed when the unit is in an OPERATIONAL CONDITION or other specified condition for which the requirements of the associated Limiting Condition for Operation are not applicable, unless otherwise specified. The SRs associated with a Special Test Exception Limiting Condition for Operation are only applicable when the Special Test Exception Limiting Condition for Operation is used as an allowable exception to the requirements of a Speci fi cation.

LIMERICK - UNIT 1 B 3/4 0-3e Amendment No. 1+/-,16-r,169, Associated with Amendment No. -21:9, 225

3/4.0 APPLICABILITY BASES

) Unplanned events may satisfy the requirements (including applicable acceptance' criteria) for a given SR. In this case, the unplanned event may be credited* as fulfilling the performance of the SR. This allowance includes those SRs whose performance is normally precluded in a given OPERATIONAL CONDITION or other specified condition.

Surveillance s, including Surveillance s invoked by ACTION requirements, do not have to be performed on inoperable equipment because the ACT!ONS define the remedial measures that apply. Surveillance s have to be met and performed in accordance with Specificatio n 4.0.2, prior to returning equipment to OPERABLE status.

Upon completion of maintenance, appropriate post maintenance testing is required to declare equipment OPERABLE. This includes ensuring applicable Surveillance s are not failed and their most recent performance is in accordance with Specificatio n 4.0.2. Post maintenance testing may not be possible in the current OPERATIONAL CONDITION or other specified conditions in the Applicabilit y due to the necessary unit parameters not having been established. In these situations, the equipment may be considered OPERABLE provided testing has been satisfactori ly completed to the extent possible and the equipment is not otherwise believed to be incapable of performing its function. This will allow operation to proceed to an OPERATIONAL CONDITION or other specified condition where other necessary post maintenance tests can be completed.

Some examples of this process are:

a. Control Rod Drive maintenance during refueling that requires scram testing at> 950 psi. However, if other appropriate testing is satisfactor ily completed and the scram time testing of Specificatio n 4.1.3.2 is satisfied, the control rod can be considered OPERABLE.

This allows startup to proceed to reach 950 psi to perform other necessary testing.

b. High pressure coolant injection (HPCI) maintenance during shutdown that requires system functional tests at a specified pressure.

Provided other appropriate testing is satisfactori ly completed, startup can proceed with HPCI considered OPERABLE. This allows operation to reach the specified pressure to complete the necessary post maintenance testing.

LIMERICK - UNIT 1 B 3/4 0-3f Amendment No. 1+/-, -lGr, 169 Associated with Amendment No. 219

3/4.0 APPLICABILilY BASES Specification 4,0.2 establishes the limit for which the specified time interval for Surveillance Requirements may be extended. It permits an allowable extension of the normal surveillance interval to facilitate surveil-C lance scheduling and consideration of plant operating conditions that may not be suitable for conducting the surveillance; e.g., transient conditions or other ongoing surveillance or maintenance activities .. It also provides flexibility to accommodate the length of a fuel cycle for surveillances that are performed at each refueling outage and are specified with an 24-month surveillance interval. It is not intended that this provision be used repeatedly to extend the surveillance intervals beyond that specified for surveillances that are not performed during refueling outages. Likewise, it is not the intent that REFUELING INTERVAL surveillances be performed during power operation unless it is consistent with safe plant operation. The limitation of Specification 4.0.2 is based on engineering judgment and the recognition that the most probable result of any particular surveillance being performed is the verification of conformance with the Surveillance Requirements. This provision is sufficient to ensure that the reliability ensured through surveillance activities is not significantly degraded beyond that obtained from the specified surveillance interval.

Specification 4,0.3 establishes the flexibility to defer declaring affected equipment inoperable or an affected variable outsid~ the specified limits when a Surveillance has not been performed within the specified Surveillance time interval and allowed extension. A delay period of up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or up to the limit of the specified Surveillance time interval, whichever is greater, applies from the point in time that it is discovered that the Surveillance has not been performed in accordance with Specification 4.0.2, and not at the time that the specified Surveillance time interval and allowed extension was not met.

When a Section 6.8, 'Procedures and Programs," specification states that the provisions of SR 4.0.3 are applicable, it permits the flexibility to defer declaring c_*-,

the testing requirement not met in accordance with SR 4.0.3 when the testing has not been completed within the testing interval (including the allowance of SR 4.0.2 i*f invoked by the Section 6.8 specification).

This delay period provides adequate time to perform Surveillances that have been missed. This delay period permits the performance of a Surveillance before complying with ACTION requirements or other remedial measures that might preclude performance of the Surveillance.

The basis for this delay period includes consideration of unit conditions, adequate planning, availability of personnel, the time required to perform the Surveillance, the safety significance of the delay in completing the required Surveillance, and the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the requirements. When a Surveillance with a Surveillance time interval based not on time intervals, but upon specified unit conditions, operating situations, or requirements of regulations (e.g., prior to entering OPERATIONAL CONDITION 1 after each fuel loading, or in accordance with 10 CFR 50, Appendix J, as modified by approved exemptions, etc.) is discovered to have not been performed when specified, Specification 4.0.3 allows for the full delay period of up to the specified Surveillance time interval to perform the Surveillance. However, since there is not a time interval specified, the missed Surveillance should be performed at the first reasonable opportunity.

Specification 4.0.3 provides a time limit for, and allowances for the performance of, Surveillances that become applicable as a consequence of OPERATIONAL CONDITION changes imposed by ACTION requirements.

LIMERICK - UNIT 1 B 3/4 0-4 Amendment No. li, -38, -11:, -3:Gr, Associated with Amendment No. 226

3/4.0 APPLICABILITY BASES Specificatio n 4.0.3 (Continued)

SR 4.0.3 is only applicable if there is a reasonable expectation the associated equipment is OPERABLE or that variables are within limits, and it is expected that the Surveillance will be met when performed. Many factors should be considered, such as the period of time since the Surveillance was last performed, or whether the Surveillance , or a portion thereof, has ever been performed, and any other indications, tests, or activities that might support the expectation that the Surveillance will be met when performed. An example of the use of SR 4.0.3 would be a relay contact that was not tested as required in accordance with a particular SR, but previous successful performances of the SR included the relay contact; the adj acen*t, physi ca11 y connected re1ay contacts were tested du ring the SR performance; the subject relay contact has been tested by another SR; or historical operation of the subject relay contact has been successful. It is not sufficient to infer the behavior of the associated equipment from the performance of similar equipment. The rigor of determining whether there is a reasonable expectation a Surveillance will be met when performed should increase based on the length of time since the last performance of the Surveillance . If the Surveillance has been performed recently, a review of the Surveillance history and equipment performance may be sufficient to support a reasonable expectation that the Surveillance will be met when performed. For Surveillance s that have not been performed for a long period or that have never been performed, a rigorous evaluation based on objective evidence should provide a high degree of confidence that the equipment is OPERABLE.

The evaluation should be documented in sufficient detail to allow a* knowledgeable i ndivi dua1 to understa_nd the basis for the determination.

Failure to comply with specified Surveillance time intervals and allowed extensions for SRs is expected to be an infrequent occurrence. Use of the delay period

__) established by Specificatio n 4.0.3 is a flexibility which is not intended to be used repeatedly to extend Surveillance intervals.

LIMERICK - UNIT 1 B 3/4 0-4a Associated with Amendment No. irS-,

226

C INTENTIONALLY LEFT BLANK c:~

C

THIS PAGE INTENTIONALLY LEFT BLANK Specification 4.0.2 establishes the limit for which. the specified time interval for Surveillance Requirements may be extended. It permits an allowable extension of the normal surveillance interval to facilitate surveil-lance scheduling and consideration of plant operating conditions that may not be suitable for conducting the surveillance; e.g., transient conditions or other ongoing surveillance or maintenance activities. It also provides flexibility to accommodate the length of a fuel cycle for surveillances that are performed at each refueling outage and are specified with an 24-month surveillance interval. It is not intended that this provision be used repeatedly as a convenience to extend the surveillance intervals beyond that specified for surveillances that are not performed during refueling outages.

Likewise, it is not the intent that REFUELING INTERVAL surveillances be performed during power operation unless it is consistent with safe plant operation. The limitation of Specification 4.0.2 is based on engineering judgment and the recognition that the most probable result of any particular surveillance being performed is the verification of conformance with the Surveillance Requirements. This provision is sufficient to ensure that the reliability ensured through surveillance activities is not significantly degraded beyond that obtained from the specified surveillance interval.

Specification 4.0.3 establishes the flexibility to defer declaring affected equipment inoperable or an affected variable outside the specified limits when a Surveillance has not been completed within the specified Surveillance time interval and allowed extension. A delay period of up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or up to the. limit of the specified Surveillance time interval, whichever is greater, applies from the point in time that it is discovered that the Surveillance hqs not ben performed in accordance with Specification 4.0.2, and not at the time that the specified Surveillance time interval and allowed extension was not met.

This delay period provides adequate time to complete Surveillances that have been missed. This delay period permits the completion of a Surveillance before complying with ACTION requirements or other remedial measures that might preclude completion of the Surveillance.

The basis for this delay period includes consideration of unit conditions-, adequate planning, availability of personnel, the time required to perform the Surveillance, the safety significance of the delay in completing the required Surveillance, and the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the requirements. When a Surveillance with a Surveillance time interval based not on time intervals, but upon specified unit conditions, operating situations, or requirements of regulations (e.g., prior to entering OPERATIONAL CONDITION 1 after each fuel loading, or in accordance with 10 CFR 50, Appendix J, as modified by approved exemptions, etc.) is discovered to have not been performed when specified, Specification 4.0.3 allows for the full delay period of up to the specified Surveillance time interval to perform the Surveillance. However, since there is not a time interval specified, the missed Surveillance should be performed at the first reasonable opportunity.

Specification 4.0.3 provides a time limit for, and allowances for the performance of, Surveillances that become applicable as a consequence of OPERATIONAL CONDITION changes imposed by ACTION requirements.

Failure to comply with specified Surveillance time intervals and allowed extensions for SRs is expected to be an infrequent occurrence. Use of the delay period established by Specification 4.0.3 is a flexibility which is not intended to be used as an operational con.venience to extend Surveillance intervals. ( __ _

LIMERICK - UNIT 1 B 3/4 0-4 Amendment No.-+/--+/--,~. t, 162

3/4.0 APPLICABILITY BA While up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or the limit of the specifi_ed Surveillance time interval is provided to p~rform the missed Surveillance, it is expected that.the missed .

Surveillance will be performed at the first reasonable opportunity. The determina-tion of the first reasonable opportunity should include consideration of the impact on plant risk (from delaying the Surveillance as well as any plant configuration changes required or shutting the plant down to perform the Surveillance) and impact on any analysis assumptions, in addition to unit conditions, planning, availability of personnel, and the time r.equired to perform the Surveillance. This risk impact should be managed through the program in plate to implement 10 CFR 50.65(a)(4) and its implementation guidance, NRC Regulatory Guide 1.1a2, 'Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants.' This Regulatory Guide addresses *consideration of temporary and aggregate r-isk impacts, determination of risk management*action thresholds, .and risk management action up to and including plant shutdown. The missed Surveillance should be treated as an emergent condition as discussed in the Regulatory Guide. The risk evaluation may use quantitative, qualitative, or blended methods. The degree of depth and rigor of the evaluation should be conmensurate with the importance of the component. Missed Surveillances for important components should be analyzed quantitatively. If the results of the risk evaluation determine the risk increase is significant, this evaluation should be used to determine the safest course of action. All missed Surveillances will be placed in the Corrective Action Program.

If a Surveillance is not completed within the allowed delay period, then the equipment is considered inoperable or the variable is considered outside the specified limits and th*e ACTION requirements for the applicable Li1iliting Condition for Operation.begin irrmediately upon expira.tion of the delay*period.* If a Surveillanc-e is failed within the delay period or the variable.is outside the specified limits, then-the equipment is inoperable and the Completion Times of the Required Actions for the applicable lCO. Conditions begin inmediately upon the failure of the Surveillance. ..

Completion of the Surveillance within the delay period allowed by this Specification, or within the allowed times specified in the ACTION requirements, restores compliance with Specification 4.0.1.

Specification 4.0.4 establishes the requirement that all applicable SRs must be met before entry into an OPERATIONAL CONDITION or other specified condition in the App 1i cabi 1i ty.

~- . ---** - -*-- ,. ___ - -- *--* -** .,.

This Specification ensures that system and component OPERABILITY requirements and variable limits are met before entry into OPERATIONAL CONDITIONS or other specified conditions in the Applicability for which these systems and components ensure safe operation of the unit. The provisions of this Specification should not be interpreted as endorsing the failure to exercise the good practice of restoring systems or romponents to OPERABLE status before entering an assoc*ated OPERATIONAL CONDITION or other specified condition in the Applicability.

A provision is included to allow entry into an OPERATIONAL CONDITION or other specified condition in the Applicability when a Limiting Condition for Operation is not met due to a Surveillance not being met i~ accordance with Specification 3.0.4.

~ However, in certain circumstances, failing to meet an SR will not result in Specification 4.0.4 restricting an* OPERATIONAL CONDITION change or other specified condition change. When a system, subsystem, division, component, device, or variable is inoperable or outside its specified limits, the associated LIMERICK - UNIT 1 B 3/4 0-5 Amendment No. i, 49, ~. ~ . 169

3/4.0 APPLICABILITY SR(s) are not required to be performed, per Specificatio n 4.0.1, which states that surveillance s do not have to be performed on inoperable equipment. When equipment is inoperable, Specificatio n 4.0.4 does not apply to the associated SR(s) since the requirement for the SR(s) to be performed is removed. Therefore, failing to perform the Surveillance (s) within the specified Surveillance time interval does not result in a Specificatio n 4.0.4 restriction to changing OPERATIONAL CONDITIONS or other specified conditions of the Applicabili ty. However, since the Limiting Condition for Operation is not met in this instance, Specificatio n 3.0.4 will govern any restrictions that may (or may not) apply to OPERATIONAL CONDITION or other specified condition changes. Specificatio n 4.0.4 does not restrict changing OPERATIONAL CONDITIONS or other specified conditions of the Applicabilit y when a Surveillance has not been performed within the specified Surveillance time interval, provided the requirement to declare the Limiting Condition for Operation not met has been delayed in accordance with Specificatio n 4.0.3.

The provisions of Specificatio n 4.0.4 shall not prevent entry into OPERATIONAL CONDITIONS or other specified conditions in the Applicabilit y that are required to comply with ACTION requirements. In addition, the provisions of Specificatio n 4.0.4 shall not prevent changes in OPERATIONAL CONDITIONS or other specified conditions in the Applicabilit y that result from any unit shutdown. In this context, a unit shutdown is defined as a change in OPERATIONAL CONDITION or other specified condition in the Applicabilit y associated with transitionin g from OPERATIONAL CONDITION 1 to OPERATIONAL CONDITION 2, OPERATIONAL CONDITION 2 to OPERATIONAL CONDITION 3, and OPERATIONAL CONDITION 3 to OPERATIONAL CONDITION 4.

Specification 4.0.S establishes the requirement that inservice inspection of ASME Code Cl ass 1, 2 and 3 components and i nservi ce testing of ASME Code Cl ass 1, 2 and 3 pumps and valves shall be performed in accordance with a periodically updated version of Section XI of the ASME Boiler and Pressure Vessel Code and Addenda, and the ASME Code for Operation and Maintenance of Nuclear POw'Jer Plants (ASME 0"1 Code) and applicable Addenda as required by 10 CFR 50.SSa. The provisions of SR 4.0.2 and SR 4.0.3 do not apply to the INSERVICE TESTING PROGRAM unless there is a specific SR referencing usage of the program.

LIMERICK - UNIT 1 B 3/4 0-6 Amendment No. li,49,i69, ~, 1:94 Associated with Amendment No. 225

3/4.1 REACTIVITY CONTROL SYSTEMS 3/4.1.1 SKUTDOWN MARGIN - - - - - - -------

A sufficient SHUTDOWN MARGIN ensures that Cl) the reactor can be made subcritical from all operating conditions, (2) the reactivity transients associated with postulated accident conditions are controllable within acceptable limits, and (3) the reactor will be maintained sufficiently subcritical to preclude inadvertent criticality in the shutdown condition.

Since core reactivity values will vary through core life as a function of fuel depletion and poison burnup, the demonstration of SHUTDOWN MARGIN will be performed in the cold, xenon-free condition and shall show the core to be subcritical by at least R + 0.38% A k/k or R + 0.28% A k/k, as appropriate.

The 0.38% A k/k includes uncertainties and calculation biases. The value of R in units of% A k/k is the difference between the calculated value of minimum shutdown margin during the operating cycle and the calculated shutdown margin at the time of the shutdown margin test at the beginning of cycle. The value of R must be positive or zero and must be determined for each fuel loading cycle.

Two different values are supplied in the Limiting Condition for Operation to provide for the different methods of demonstration of the SHUTDOWN MARGIN.

The highest worth rod may be determined analytically or by test. The SHUTDOWN MARGIN is demonstrated by (an insequence) control rod withdrawal at the beginning of life fuel cycle conditions, and, if necessary, at any future time in the cycle if the first demonstration indicates that the required margin could be reduced as a function of exposure. Observation of subcriticality in this condition assures subcriticality with the most reactive control rod fully withdrawn.

This reactivity characteristic has been a basic assumption in the analysis of plant performance and can be best demonstrated at the time of fuel loading, but the margin must also be determined anytime a control rod is incapable of insertion.

3/4.1.2 REACTIVITY ANOMALIES Since the SHUTDOWN MARGIN requirement for the reactor is small, a careful check on actual conditions to the predicted conditions is necessary, and the changes in reactivity can be inferred f~om these comparisons of core keffective

<keff>* Since the comparisons are easily done, frequent checks are not an i.mposition on normal operations. A 1% chang-e is larger than is expected for normal operation so a chang~ of this magnitude should be thoroughly evaluated.

A change as large as 1% would not exceed the design conditions of the reactor and is on the safe side of the postulated transients.

LIMERICK - UNIT 1 B 3/4 1-1 Associated with Amendment No. 207

REACTIVITY CONTROL SYSTEMS BASES 3/4.1.3 CONTROL RODS The specification of this section ensure that (1) the minimum SHUTDOWN MARGIN is maintained, (2) the control rod insertion times are consistent with those used in the accident analysis, and (3) the potential effects of the rod drop accident are limited. The ACTION statements permit variations from the basic requirements but at the same time impose more restrictive criteria for continued operation; A limitation on inoperable rods is set such that the resultant effect on total rod worth and scram shape will be kept to a minimum. The requirements for the various scram time measurements ensure that any indication of systematic problems with rod drives will be investigated on a timely basis.

Damage within the control rod drive mechanism could be a generic problem, therefore with a control rod immovable because of excessive friction or mechanical interference, operation of the reactor is limited to a time period which is reasonable to determine the cause of the inoperability and at the same time prevent operation with a large number of inoperable control rods.

Control rods that are inoperable for other reasons are permitted to be taken out of service provided that those in the nonfully-inserted position are consistent with the SHUTDOWN MARGIN requirements.

The number of control rods permitted to be i_noperable could be more than the eight allowed by the specification, but the occurrence of eight inoperable rods could be indicative of a generic problem and the reactor must be shutdown for investigation and resolution of the problem. ~ *

• ~.. ~*

The control rod system is designed to bring the reactor subcritical at a rate fast enough to prevent the MCPR from becoming less than the fuel cladding safety limit during the limiting power transient analyzed in Section 15.2 of the FSAR. This analysis shows that the~negative reactivity rates resulting from the scram with the average response of all the drives as given in the specifi-cations, provided the required protection and MCPR remains greater than the fuel cladding safety limit. The occurrence of scram times longer then those specified should be viewed as an indication of a systemic problem with the rod drives and therefore the surveillance interval is reduced in order to prevent operation of the reactor for long periods of .time with a potentially serious problem.

Scram time testing at zero p~ig reactor coolant pressure is adequate to ensure that the control rod will perform its intended scram function during startup of the plant until scram time testing at 950 psig reactor coolant pressure is performed prior to exceeding 40% rated core thermal power. .

The scram discharge volume is required to be OPERABLE so that it will be available when needed to accept discharge water from the control rods during a reactor scram and will isolate the. reactor coolant system from the containment when required.

The OPERABILITY of all SDV vent and drain valves ensures that the SDV vent and drain valves will close during a scram to contain reactor water discharged to the SDV piping. The SDV has one common drain line and one corrvnon vent line. Since the vent and drain lines are provided with two valves in series, the single failure of one valve in LIMERICK - UNIT 1 B 3/4 1-2 Amendment No. 60, .g.g., 168

REACTIVITY CONTROL SYSTEMS BAE J

---,fGN +RGl-R -GDS-- t-(-hCo -nt.:i--l 'l.ue 1------- --------- -----

the open position will not impair the isolation function of the system. Additiona lly, the valves are required to open on scram reset to ensure that a path is available for the SOV piping.to drain freely at other times.

When one SDV vent or drain valve is inoperable in one or more lines, the valves must be restored to OPERABLE status within 7 days. The allowable outage time is.

reasonabl e, given the level of redundancy in the lines and the low probabili ty of a scram occurring while the valve(s) are inoperable. The SDV is still isolable since the redundant valve in the affected line is OPERABLE. During these periods, the single failure criterion may not be preserved, and a higher risk exists to allow reactor water out of the primary system during a scram.

If both valves in a line are inoperable, the line must be isolated to contain the reactor coolant during a scram. When a line is isolated, the potential for an inadverte nt SGram due to high SDV level is increased. ACTION "e" is modified by a note("*** *") that allows periodic draining and venting of the SDV when a line is isolated. During the~e periods, the line may be unisolated under administr ative control. This allows any a~cumulated water in the line to be drained, to preclude a reactor scram on SDV high level. This is acceptable since the administr ative controls ensure the valve can be closed quickly, by a dedicated operator, if a scram occurs with the ~alve open. The 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> allowable outage time to isolate the line is based on the low probabili ty of a scram occurring while the line is not isolated and the unlikeliho od of significa nt CRD seal leakage.

• Control rods with inoperable accumulators are declared inoperable and Specifica tion 3.1.3.1 then applies. This prevents a pattern of inoperable accumulators that would result in less reactivity insertion on a scram than has been analyzed even though control rods with inoperable accumulators may still be inserted with normal drive water pressure. The drive water pressure normal operating range is specified in system operating procedures which provide ranges for system alignment and control rod motion (exercisin g). Operabili ty of the accumulator ensures that there is a means available to insert the control rods even under the most unfavorable depres*suri zati on of the reactor. A control rod is considered trippable if it is capable of fully inserting as a result of a scram signal.

LIMERICK - UNIT 1 B 3/4 1-2a Amendment No . .J.0, .Q.9., ~ . 178

THIS PAGE INTENTIONALLY LEFT BLANK REACTIVITY CONTROL SYSTEMS

..~J gBA~~================~================

'~ CONTROL RODS . (Continued)

Control rod coupling integrity is required to ensure compliance with the analysis of the rod drop accident in the FSAR. The overtravel position feature provides the only positive means of determining that a rod is properly coupled and therefore this check must be performed prior to achieving criticality after completing CORE ALTERATIONS that could have affected the control rod coupling integrity. The subsequent check is performed as a backup to the initial demon-stration.

• In order to ensure that the control rod-patterns can be followed and there-fore that other parameters.are within their limits, the control rod position indication system must be OPERABLE.

The control rod housing support restricts the outward movement of a control rod to less than 3 inches in the event of a housing failure. The amount of rod reactivity*which could be added by this small amount of rod withdrawal is less than a normal withdrawal increment and will not contribute to any damage to the primary coolant system. The support is not required when there is no pressure to act as a driving force to rapidly eject a drive housing.

The required surveillances ~re adequ~te to determine that the rods are OPERABLE and not so frequent as to cause excessive wear on the system components.

3/4.1.4 CONTROL ROD PROGRAM CONTROLS Control rod withdrawal and in5ertion sequences are established to assure that the maximum insequence individual control rod or control rod segments which ar~ withdrawn at any time during the fuel cycle could not be worth enough to result in a peak fuel enthalpy greater than 280 cal/gm in the event of a control rod drop accident. The specified sequences are characterized by homogeneous, scattered patterns of control rod withdrawal. When THERMAL POWER is greater than 10% of RATED THERMAL POWER, there is no possible rod worth which, if dropped at the design rate of the velocity limiter, could result in a peak enthalpy of 280 cal/gm. Thus requiring the RWM to be OPERABLE when THERMAL POWER is less than-or equal to 10% of RATED THERMAL POWER provides adequate control.

• The RWM provides automatic supervision to assure that out-of-sequence rods will not be withdrawn or inserted.

The analysis of the rod drop accident is presented in Section 15.4.9 of the FSAR and the techniques of the analysis are presented in a topical report, Reference 1, and two supplements, References 2 and 3. Additional pertinent analysis is also contained in Amendment 17 to the Reference 4 topical report.

The RBM is designed to automatically prevent fuel damage in the event of erroneous rod withdrawal from locations of high power density over the range of power operation. Two channels are provided. Tripping one of the channels will block erroneous rod withdrawal to prevent fuel damage. This system backs up the written sequence used by the operator for withdrawal of control rods. RBM OPERA-BILlTY is required when the limiting condition described in Specification 3.1.4.3 exists.

LIMERICK - UNIT 1 B 3/4 1-3 Amendment No. 1-7, ~J.86

REACTIVITY CONTROL SYSTEMS 3/4.1.5 STANDBY LIQUID CONTROL SYSTEM

(~

The standby liquid control system provides a backup capability for bringing the reactor from full power to a cold, Xenon-free shutdown, assuming that the withdrawn control rods remain fixed in the rated power pattern. To meet this objective it is necessary to inject a quantity of boron which produces a concen-tration of 660 ppm in the reactor core and other piping systems connected to the reactor vessel. To allow for potential leakage and improper mixing, this concentration is increased by 25%. The required concentration is achieved by having available a minimum quantity of 3,160 gallons of sodium pentaborate solution contai.nng a minimum of 3,754 lbs of sodium pentaborate having the requisite Boron-10 atom% enrichment of 29% as determined from Reference 5.

This quantity of solution is a net amount which is above the pump suction shutoff level setpoint thus allowing for the portion which cannot be injected.

The above quantities calculated at 29% Bdron-10 enrichment have been demonstrated by analysis to provide a Boron-10 weight equivalent of 185 lbs in the sodium pentaborate solution. Maintaining this Soron-10 weight in the net tank contents ensures a sufficient quantity of boron to bring the reactor to a cold, Xenon-free shutdown.

The pumping rate of 37.0 gpm provides a negative reactivity insertion rate over the permissible solution volume range, which adequately compensates for the positive reactivity effects due to elimination of steam voids, increased water density from hot to cold, reduced doppler effect in uranium, reduced neutron leakage from boiling to cold, decreased control rod worth as the moderator cools, and xenon decay. The temperature requirement ensures that the sodium pentaborate always remains in solution.

With redundant pumps and explosive injection valves and with a highly reliable control rod scram system, operation of the reactor is permitted to

(:____ .

continue for short periods of time with the system inoperable or for longer periods of time with one of the redundant components inoperable.

The SLCS system consists of three separate and independent pumps and explosive valves. Two of the separate and independent pumps and explosive valves are required to meet the minimum requirements of this technical specification and, where applicable, satisfy the single failure criterion. To ensure that SLCS pump discharge pressure does not exceed the SLCS relief valve setpoint during operation following an anticipated transient without scram (ATWS) event, no more than two pumps shall be aligned for automatic operation in OPERATIONAL CONDITIONS l, 2, and 3. This maintains the equivalent control capacity to satisfy 10 CFR 50.62 (Requirements for reduction of risk from anticipated transients without scram (ATWS). With three pumps aligned for automatic operation, the system is inoperable and ACTION statement (b) applies.

The SLCS must have an equivalent control capacity of 86 gpm of 13%

weight sodium pentaborate in order to satisfy 10 CFR 50.62. As part of the ARTS/MELLL program the ATWS analysis was updated to reflect the new rod line. As a result of this it was determined that the Boron 10 enrichment was required to be increased to 29% to prevent exceeding a suppression pool temperature of 190°F. This equivalency requirement is fulfilled by having a system which satisfies the equation given in 4.1.5.b.2.

The upper limit concentration of 13.8% has been established as a reasonable limit to prevent precipitation of sodium pentaborate in the event of a loss of tank heating, which allow the solution to cool. A SLCS Pump flowrate of 37.0 gpm (minimum) and a Sodium Pentaborate Solution concentration of 9% by weight (minimum) will require a Boron-10 enrichment of 49 atom% to be added to the tank. The decreased pump flowrate and increased solution enrichment are acceptable because the results of the ATWS Rule Equation will remain> 1.0. l LIMERICK - UNIT 1 B 3/4 1-4 Amendment No.~.~.~.

Associated with Amendment~. 232

REACTIVITY CONTROL SYSTEMS j) STANDBY LIQUID CONTROL SYSTEM (Continued)

Surveillance requirements are established on a frequency that assures a_

high reliability of the system. Once the solution is established, boron con-centration will not vary unless more boron or water is added, thus a check on the temperature and volume assures that the solution is available for use.

Replacement of the explosive charges in the valves will assure that these valves will not fail because of deterioration of the charges.

The Standby Liquid Control* System also has a post-OBA LOCA safety function to buffer Suppression Pool pH in order to maintain bulk pH above 7.0. The buffering of Suppression Pool pH is necessary to prevent iodine re-evolution to satisfy the methodology for Alternative Source Term. Manual initiation is used, and the minimum amount of total boron required for Suppression Pool pH buffering is 256 lbs. Given that at least 185 lbs of Boron-10 is maintained in the tank, the total boron in the tank will be greater than 256 lbs for the range of enrichments from 29% to 62%.

ACTION Statement (a) applies only to OPERATIONAL CONDITIONS 1 and 2 because a single pump can satisfy both the reactor control function and the post-OBA LOCA function to control Suppression Pool pH since boron injection is not required until 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> post-LOCA. ACTION Statement (b) applies to OPERATIONAL CONDITIONS 1, 2 and 3 to address the post-LOCA safety function of the SLC system.

1. C. J. Paone, R. C. Stirn and J. A. Woolley, "Rod Drop Accident Analysis for Large BWR's," G. E. Topical Report NED0-10527, March 1972.

2. C. J. Paone, R. C. Stirn, and R. M. Young, Supplement 1 to NED0-10527, July 1972.

3. J.M. Haun, C. J. Paone, and R. C. Stirn, Addendum 2, "Exposed Cores,"

Supplement 2 to NED0-10527, January 1973.

4. Amendment 17 to General Electric Licensing Topical Report NEDE-24011-P-A, "General Electric Standard Application for Reactor Fuel."

5. "Maximum Extended Load Line Limit and ARTS Improvement Program Analyses for Limerick Generating Station Units 1 and 2," NEDC-32193P, Revision 2, October 1993.

LIMERICK - UNIT 1 B 3/4 1-5 Amendment No.~.~.~ .~

ECR 09-00406

PAGE INTENTIONALLY LEFT BLANK 3/4.2 POWER DISTRIBUTION LIMITS BASES 3/4.2.1 AVERAGE PLANAR LINEAR .HEAT GENERATION RATE

~~)~~ ~~.--1 his_s __J:2 ecific ation assures that the peak claddi ng temperature (PCT) following the postulated design basis Loss-of=-Coolant Accide nt (LO-CA} w1l1 nor-- -

the fuel exceed the limits specified in 10 CFR 50.46 and that not be exceed design analysis limits specified- in NEOE-24011-P-A (Reference 2) will ed._

Mechanical Design Analysis: NRC approved methods (speciefied in Refer-ence 2) are used to demonstrate that all fuel rods in a lattic operat ing at the bounding power history, meet the fuel design limits specif ied in Reference 2.

No single fuel rod follows, or is capable of following, this boundi fuel design ng power histor y. This bounding power histor y is usec as the basis for the analysis MAPLHGR limit.

LOCA Analysis: A LOCA analysis is performed in accordance with 10 CFR 50 Appendix K to demonstrate that the permissible planar power (MAPLHGR) limits comply with the ECCS limits specif ied in 10 CFR 50.46. The analys is is performed for the most limiting break size, break location, and single failur e combination for the plant, using the evaluation model described in Reference 9.

The MAPLHGR limit as showm in the CORE OPERATING LIMITS REPORT is the most limiti ng composite of the fuel mechanical design anaylsis MAPLHGR and the ECCS MAPLHGR limit.

Only the most-limiting MAPLHGR values are shown in the CORE OPERATING LIMITS REPORT for multiple lattic e fuel. Compliance with the specif ic lattic e use MAPLHGR operating limits , which are available in Reference 3, is ensured by of the process computer.

As a result of no longer utiliz ing an APRM trip setdownnce requirement, additional constr aints are placed on the MAPLHGR limits to assure adhere to the fuel-mechanical design bases. These constr aints are introduced through the MAPFA C(P) and MAPFAC(F) factors as defined in the COLR.

B 3/4 2-1 Amendment No. 7, Z0, Z7, 66 LIMERICK - UNIT l f EB 1 O 1994

POWER DISTRIBUTION LIMITS ,...... ;

BASES ... , ,.:. ......... -** ..,.-... .. ." ..** r ~ ~

3/4.2.2 <DELETED)

.;

INFORMATION CONTAINED ON THIS PA6E HAS BEEN DELETED LIMERICK - UNIT 1 B 3/4 2-2 Amendment No. 7, z~, 66 f EB 10 1994

LEFT INTENTIONALLY BLANK LIMERICK - UNIT 1 B 3/4 2-3 Amendment No. 7 I

POWER DISTRIBUTION LIMITS 3/4.2.3 MINIMUM CRITICAL POWER RATIO The required operating limit MCPRs at steady-state ~perating conditions as specified in Specification 3.2.3 are derived from the established fuel cladding integrity Safety Limit MCPR, and an analysis of abnormal operational transients. For any abnormal operating transient analysis evaluation with the initial condition of the reactor being at the steady-state opera\ing limit, it is required that less than 0.1% of fuel rods in the core are susceptible to transition boiling or that the resulting MCPR does not decrease below the Safety Limit MCPR at any time during the transient assuming instrument trip setting given in Specification 2.2.

To assure that the fuel cladding integrity Safety Limit is not exceeded during any anticipated abnormal operational transient, the most limiting tran-sients have been analyzed to determine which result in the largest reduction in CRITICAL POWER RATIO (CPR). The type of transients evaluated were loss of flow, increase in pressure and power, positive reactivity insertion, and coolant temperature decrease.

The evaluation of a given transient begins with the system initial para-meters shown in FSAR Table 15.0-2 that are input to a BWR system dynamic behavior transient computer program. The codes used to evaluate transients are discussed in Reference 2.

• The MCPR operating limits derived from the transient analysis are dependent on the operating core flow and power state (MCPRCF), and MCPR(P), respectively) to ensure adherence to fuel design limits during the worst transient that occurs with moderate frequency (Ref. 6). Flow dependent MCPR limits (MCPR~F)) are determined by steady state thermal hydraulic methods with key physics response inputs benchmarked using the three dimensional BWR simulator code (Ref. 7) to analyze slow flow runout transients.

Power dependent MCPR limits (MCPR(P)) are determined by the codes used to evaluate transients as described in Reference 2. Due to the sensitivity of the I.

transient response to initial core flow levels at power levels below those at which the turbine stop valve closure and turbine control valve fast closure scrams are bypassed, high and low flow MCPRCP), operating limits are provided for operating between 25% RTP and 30% RTP.

The MCPR operating limits specified in the COLR are the result of the Design Basis Accident (OBA) and transient analysis. The operating limit MCPR is determined by the larger of the MCPR(F), and MCPR(Pl limits.

LIMERICK - UNIT 1 B 3/4 2-4 Amendment No.+, 9-, ~. J.7., -6&

~G~ LG 99 Glld8, ECR 11-00092

POWER DISTRIBUTION LIMITS BASES MINIMUM CRITICAL POWER RATIO (Continued)

J_

At THERMAL POWER levels less than or equal to 25% of RATED THERMAL POWER, the reactor will be operating at minimum recirculation pump speed and the moderator void -a>ntent will be very small. For all designated control rod patterns which may be employed at this point, operating plant experience indi-cates that the resulting MCPR value is in excess of requirements by a considerable margin. During initial start-up testing of the plant, a MCPR evaluation will be made at 25% of RATED THERMAL POWER level with minimum recirculation pump speed. The MCPR margin will thus be demonstrated such that future MCPR evaluation below this power level will be shown to be unnecessary. The daily requirement for calculating MCPR when THERMAL POWER is greater than or equal to 25% of RATED THERMAL POWER is sufficient since power distribution shifts are very slow when there have not been significant power or control rod changes. The require-ment for calculating MCPR when a limiting control rod pattern is approached ensures that MCPR will be known following a change in THERMAL POWER or power shape, regardless of magnitude, that could place operation at a thermal limit.

3/4.2.4 LINEAR HEAT GENERATION RATE This specification assures that the Linear Heat Generation Rate (LHGR) in any rod is less than the design linear heat generation even if fuel pellet densification is postulated.

Reference:

l. Deleted.

2. "General Electric Standard Application for Reactor Fuel,"

NEDE-24011-P-A (latest approved revision).

3. "Basis of MAPLHGR Technical Specifications for Limerick Unit l,"

NED0-31401, February 1987 (as amended).

4. Deleted

5. Increased Core Flow and Partial Feedwater Heating Analysis for Limerick Generating Station Unit 1 Cycle 1, NEDC-31323, October 1986 including Errata and Addenda Sheet No. 1 dated November 6, 1986.

6. NEDC-32193P, nMaximum Extended Load Line Limit and ARTS Improvement Program Analyses for Limerick Generating Station U_nits 1 and 2," Revision 2, October 1993.

7. NED0-30130-A, :steady State Nuclear Methods," Hay 1985.

8. NED0-24154, "Qualification of the One-Dimensional Core Transient Model for Boiling Water Reactors, "October 1978.

9. NEDC-32170P, "Limerick Generating Station Units 1 and 2 SAFER/GESTR-LOCA Loss-of-Coolant Accident Analysis,n June 1993.

B 3/4 2-5 Amendment No. 7, 1~, j7, 66 LIMERICK - UNIT 1 f EB 1 O \99 4

./

~ *~. .

PAGE INTENTIONALLY LEFT BLANK i k __

3/4.3 INSTRUMENTATION 3/4,3,1 REACTOR PROTECTION SYSTEM INSTRUMENTATION The reactor protection system automatically initiate s a reactor scram to:

a. Preserve the integrity of the fuel cladding.

b. Preserve the integrity of the reactor coolant system.

c. Minimize the energy which must be adsorbed following a loss-of-coolant accident, and

d. . Prevent inadvertent critical ity.

Thil specific ation provides the limiting conditions for operatio necessary.to preserve the ability of the system to perform its intendedn function even during periods when instrument channels may be out of service because ~f maintenance. When necessary, one channel may be made inoperable for brief interval s to conduct required surveillance.

The reactor protection system is made ~p of two independent trip systems.

There are usually four channels to monitor each parameter with two channels trip system. The outputs of the channels in a trip system are combined in ainlogic each that either channel will trip that trip system. The tripping of both trip systems so wi 11 produce a reactor scram. The APRM system is di vfded H1t9 four four. 2-0ut-Of-4 Voter channels. Each APRM channel provides inputs toAPRM each channels and four voter channels. The four vot*er channels are divided into two groups ofoftwo the each, with each group of two providing inputs ~o one RPS trip system. The system is designed to a11 ow one APRM channel, but no voter channels, to be bypassed .

The system meets the intent of IEEE-279 for nuclear power plant systems. Surveillance intervals are determined in accordance with the protectio Surveilla n

Frequency Control Program and maintenance outage times have been determined in nce accordance with NEDC-30851P-A, "Technical Specification Improvement Analyses for BWR Reactor Protection System" and NEDC-32410P-A, "Nuclear. .Measurement Analysis and Control Power Range Neutron Monitor CNUMAC PRNM) Retrofit Plus Option III Stabilit y Trip Function.N The bases for the trip settings of the RPS are discusse d in the bases for Specification 2.2.1.

The APRM Functions include five Functions accomplished by the channels (Functions 2.a,.2.b , 2.c, 2.d, and 2.f) and one accomplishedfour by APRM the four 2-0ut-Of-4 Voter channels (Function 2.e). Two of the five Functions accomplished by the APRM channels are based on neutron flux only (Functions 2.a and 2.c), one Function is based on neutton flux and reci~culation drive flow (Function 2.b) and one is based on equipment status (Function 2.d). The fifth Function accomplished by the APRM channels is the Oscillation Power Range Monitor (OPRM) Upscale Function 2.f, which is based on detecting oscillat ory charact ~ristics in trip

,flux. The OPRM Upscale Function is also dependent on average neutron fluxthe neutron (Simulated Tfiermal Power) and recircul ation drive flow, which are used to automatically enable the output trip.

The Two-Out-Of-Four Logic Module includes,2-0ut-Of-4 Voter hardware and the APRM Interface hardware. The 2-0ut-Of-4 Voter Function 2.e votes APRM Function 2.b, 2.c, and 2.d independently of Function 2.f. This voting is accomplished bys the 2.a, 2-0ut-Of-4 Vot~r hardware in the Two-Out-Of-Four Logic Module.

separate outputs to RPS for the two independently voted sets of The voter includes Function s, each of which is redundant (four total outputs). The analysis in Reference 2 took credit for this redundancy in the *justific ation of the 12-hour allowed out-of-s ervice time for LIMERICK - UNIT 1 B 3/4 3-1 Amendment No * .Y, 8Q., ~ . -14+. *7-7,

3/4.3 INSTRUMENTATION 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION (continued)

Action b, so the voter Function 2.e must be declared inoperable if any of its C

function ality is inoperable. The voter Function 2.e does not need to be declared inoperable due to any failure affectin g only the APRM Interfac e hardware portion of the Two-Out-Of-Four Logic Module.

Three of the four APRM channels and all four of the voter channels are required to be OPERABLE to ensure that no single failure will valid signal. To provide adequate coverage of the entire core,precludeconsiste a scram on a design bases for the APRM Functions 2.a, 2.b, and 2.c, at least 20 LPRM nt with the inputs, with at least three LPRM inputs from each of the four axial levels at which the located, must be operable for each APRM channel. In addition , no more than LPRMs 9 are LPRMs may be bypassed between APRM calibrat ions (weekly gain adjustm ents). For the OPRM Upscale Function 2.f, LPRMs are assigned to "cells" of 3 or 4 detector s. A minimum of 23 cells (Reference 9), each with a minimum of 2 OPERABLE for each APRM channel for the OPRM Upscale Function 2.f to be LPRMs, must be OPERABLE OPERABLE channel. LPRM gain settings are determined from the local flux profilesin measured that the TIP system. This establis hes the relative local flux profile for appropriate by represen tative input to the APRM System. The 2000 EFPH frequency is based on operatin g experience with LPRM sensitiv ity changes.

References 4, 5 and 6 describe three algorithms for detectin g thermal-hydrauli c instabil ity related neutron flux oscillat ions: the period based detectio n algorithm , the amplitude based algorithm, and the growth rate algorithm. All three are implemented in the OPRM Upscale Function, but the safety analysis only for the period based detectio n algorithm. The remaining algorithmtakes s credit provide defense in depth and addition al protecti on against unantici pated oscillat ions. OPRM Upscale Function OPERABILITY for Technical Specific ation purposes is based only on the period based detectio n algorithm.

An OPRM Upscale trip is issued from an APRM channel when the period based detectio n algorithm in that channel detects oscillato ry changes in the neutron flux, c_~:,

indicate d by the combined signals of the LPRM detector s in any cell, confirmations and relative cell amplitude exceeding specifie d setpointwiths.

period One cells in a channel exceeding the trip conditions will result in a channel trip.or Anmore OPRM Upscale trip is also issued from the channel if either the amplitude based algorithms detect growing oscillato ry changes in growth the rate or neutron flux for one or more eel 1s in that channel .

The OPRM Upscale Function is required to be OPERABLE when the plant is at

~ 25% RATED THERMAL POWER. The 25% RATED THERMAL POWER level is selected to provide margin in the unlikely event that a reactor power increase transien t occurring while the plant is operating below 29.5% RATED THERMAL POWER causes a power increase to or beyond the 29.5% RATED THERMAL POWER OPRM Upscale trip auto-enable point without operator action. This OPERABILITY requirement assures that the OPRM Upscale trip automatic-enable function will be OPERABLE when required .

Actions a, band c define the Action(s) required when RPS channels are discovered to be inoperable. For those Actions, separate entry for each inoperable RPS channel. Separate entry means that the conditio allowabl n is allowed clock(s) for Actions a, b or c start upon discovery of inoperab ility fore that time specific channel. Restoration of an inoperable RPS channel satisfie s only the action statements for that particul ar channel. Action statemen channel(s) must be met according to their original entry t(s) time.

for remaining inoperable A Note has been provided to modify the Actions when Functional Unit 2.b and 2.c channels are inoperable due to failure of SR 4.3.1.1 and gain adjustments are necessary. The Note allows entry into associated Actions to be delayed for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> if the APRM is indicati ng a lower power value than the calculat ed power (i.e., the gain adjustment factor (GAF) is high (non-co nservati ve)). The GAF for any channel is defined as the power value determined by the heat balance divided ,-

by the APRM reading for that channel. Upon completion of the gain adjustment, or LIMERICK - UNIT 1 B 3/4 3-la Amendment No. -6J,8-9,~,..JA.!..-l-7+,+9-s, Associated with Amendment 2-0-+, 233

3/4.3 INSTRUMENTATION

) 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION (continued) expiration of the allowed time, the channel must be returned to OPERABLE status or the applicable Actions taken. This Note is based on the time required to perform gain adjustments on multiple channels.

Because of the diversity of sensors available* to provide trip signals and the redundancy of the RPS design, an allowable out of service time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> has been shown to be acceptable (NEDC-30851P-A and NEDC-32410P-A) to permit restoration of any inoperable channel to OPERABLE status. However, this out of service time is only acceptable provided that the associated Function's (identified as a "Functional Unit" in Table 3.3.1-1) inoperable channel is in one trip system and the Function still maintains RPS trip capability.

The requirements of Action a are intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same trip system for the same Function result in the Function not maintaining RPS trip capability. A Function is consjdered to be maintaining RPS trip capability when sufficient channels are OPERABLE or in trip (or the associated trip system is in trip), such that both trip systems will generate a trip signal from the given Function on a valid signal.

For the typical Function with one-out-of-two taken twice logic, including the IRM Functions and APRM Function 2.e (trip capability associated with APRM Functions 2.a, 2.b, 2.c, 2.d, and 2.f are discussed below), this would require both trip systems to have one channel OPERABLE or in trip (or the associated trip system in trip).

For Function 5 (Main Steam Isolation Valve--Closure), this would require both trip systems to have each channel associated with the MSIVs in three main steam lines (not necessarily the same main steam lines for both trip systems) OPERABLE or in trip (or the associated trip system in trip).

For Function 9 (Turbine Stop Valve-Closure), this would require both trip systems to have three channels, each OPERABLE or in trip (or the associated trip system in trip).

The completion time to satisfy the requirements of Action a is intended to allow the operator time to evaluate and repair any discovered inoperabilities .. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.

With trip capability maintained, i.e., Action a satisfied, Actions band c as applicable must still be satisfied. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, Action b requires that_ the channel or the associated trip system must be placed in the tripped condition.

Placing the.inoperable channel in trip (or the associated trip system in trip) would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue.

As noted, placing the trip system in trip is not applicable to satisfy Action b for APRM functions 2.a, 2.b, 2.c, 2.d, or 2.f. Inoperability of one required APRM channel affects both trip systems. For that condition,. the Action b requirements can only be satisfied by placing the inoperable APRM channel in trip. Restoring OPERABILITY or placing the inoperable APRM channel in trip are the only actions that will restore capability to accommodate a single APRM channel failure. Inoperability of more than one required APRM channel of the same trip function results in loss of trip capability and the requirement to satisfy Action a.

LIMERICK - UNIT 1 B 3/4 3-lb Amendment No. 141, 177, Associated with Amendment 233

/

3/4.3 INSTRUMENTATION 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION (continued) C The requirements of Action c must be satisfied when, for any one or more Functions, at least one required channel is inoperable in each trip system. In this condition , provided at least one channel per trip system is OPERABLE, normally the RPS still maintains trip capability for that Function, but cannot accommodate a single failure in either trip system (see additional bases discussion above related to loss of trip capability and the requirements of Action a, and special cases for Functions 2.a, 2.b, 2.c, 2.d, 2.f, 5 and 9).

The requirements of Action c limit the time the RPS scram logic, for any Function, would not accommodate single failure in both tip systems (e.g., one-out-of-one and one-out-of-one arrangement for a typical four channel Function). The reduced reliabilit y of this logic arrangement was not evaluated in NEDC-30851P-A for the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Completion Time. Within the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowance, the associated Function must have all required channels OPERABLE or in trip (or any combination) in one trip system.

Completing the actions required by Action c restores RPS to a reliabilit y level equivalent to that evaluated in NEDC-30851P-A, which justified a 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowable out of service time as allowed by Action b. To satisfy the requirements of Action c, the trip system in the more degraded state should be placed in trip or, alternativ ely, all the inoperable channels in that trip system should be placed in trip (e.g., a trip system with two inoperable channels could be in a more degraded state than a trip system with four inoperable channels if the two inoperable channels are in the same Function while the four inoperable channels are all in different Functions). The decision of which trip system is in the more degraded state should c*_-_-

be based on prudent judgment and take into account current plant conditions (1 .e.,

what OPERATIONAL CONDITION the plant is in). If this action would result in a scram or RPT, it is permissible to place the other trip system or its inoperable channels in trip.

The 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowable out of service time is judged acceptable based on the remaining capability to trip, the diversity of the sensors available to provide the trip signals, the low probabilit y of extensive numbers of inoperabi lities affecting all diverse Functions, and the low probabilit y of an event requiring the initiation of a scram.

As noted, Action c is not applicable for APRM Functions 2.a, 2.b, 2.c, 2.d, or 2.f.

Inoperabi lity of an APRM channel affects both trip systems and is not associated with a specific trip system as are the APRM 2-0ut-Of-4 voter and other non-APRM channels for which Action c applies. For an inoperable APRM channel, the requirements of Action b can only be satisfied by tripping the inoperable APRM channel. Restoring OPERABILITY or placing the inoperable APRM channel in trip are the only actions that will restore capability to accommodate a single APRM channel failure.

If it is not desired to place the channel (or trip system) in trip to satisfy the requirements of Action a, Action b or Action c (e.g., as in the case where placing the inoperable channel in trip would result in a full scram), Action d requires that the Action defined by Table 3.3.1-1 for the applicable Fun~tion be initiated immediately upon expiration of the allowable out of service time.

Table 3.3.1-1, Function 2.f, references Action 10, which defines the action required if OPRM Upscale trip capability is not maintained. Action 10b is required to address identified equipment failures. Action 10a is to address common mode vendor/industry identified issues that render all four OPRM channels inoperable at once. For this condition, References 2 and 3 justified use of alternate methods to

(_

LIMERICK - UNIT 1 B 3/4 3-lc Amendment No. 141, 177, Associated with Amendment 233

3/4.3 INSTRUMENTATION B

) 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION (continued) det~ct and suppress oscillations for a limited period of time, up to 120 days. The alternate methods are procedurally established consistent with the guidelines identified in Reference 7 requiring manual operator action to scram the plant if certain predefined events occur. The 12-hour allowed completion time to i.mplement the alternate methods is based on engineering judgment to allow orderly transition to the alternate methods while limiting the period of time during which no automatic or alternate detect and suppress trip capability is formally in place. The 120-day period during which use of alternate methods is allowed is intended to be an outside limit to allow for the caie where design changes or extensive analysis might be required to understand or correct some unanticipate d characteris tic of the instability detection algorithms or equipment. The evaluation of the use of alternate methods concluded, based on engineering judgment, that the likelihood of an instability event that could not be adequately handled by the alternate methods during the 120-day period was negligibly small. Plant startup may continue while operating within the allowed completion time of Action lOa. The primary purpose of this is to allow an orderly completion, without undue impact OJL pl an:t__ ope r ati o_n_, __ o_f_ de sJ g_n __ and ... v. e.r. .Lf.i. cat.i on-a cti vi t-i e-s- -i-n-- t h-e--eve-n-t--of- a--------- ---------

required design change to the OPRM Upscale function. This exception is not intended as an alternative to restoring inoperable equipment to OPERABLE status in a timely manner.

Action 10a is not intended and was not evaluated as a routine alternative to returning failed or inoperable equipment to OPERABLE status. Correction of routine equ1pment failure or inoperabili ty is expected to be accomplished within the completion times allowed for LCO 3.3.1 Action a or Action b, as applicable.

Action 10b applies when routine equipment OPERABILITY cannot be restored within the allowed completion times of LCD 3.3.1 Actions a orb, or if a common mode OPRM deficiency cannot be corrected and OPERABILITY of the OPRM Upscale Function restored within the 120-day allowed completion time of Action lOa.

The OP~M Upscale trip output shall be automatical ly enabled (not-bypass ed) when APRM Simulated Thermal Power is~ 29.5% and recirculatio n drive flow is< 60%

as indicated by AP~M measured recirculatio n drive flow. NOTE: 60% recirculatio n driv~ flow is the recirculatio n drive flow th~t corresponds to 60% of rated cor~

flow. This is the operating region where actual thermal-hyd raulic instability and related neutron flux oscillations may occur. As noted in Table 4.3.1.1-1, Note c, CHANNEL CALIBRATION for the OPRM Upscale trip Function 2.f includes confirming that the auto-enable (not-bypassed) setpoints are correct. Other surveillanc es ensure that the APRM Simulated Thermal Power properly correlates with THERMAL POWER (Table 4.3.1.1-1, Noted) and that recirculatio n drive flow properly correlates with core flow (Table 4.3.1.1-1, Note g).

If any OPRM Upscale trip auto-enable setpoint is exceeded and the OPRM Upscale trip is not enabled, i.e., the OPRM Upscale trip is bypassed when APRM Simulated Thermal Power is~ 29.5% and recirtlfT'atio n drive flow is< 60%, then the affected channel is considered inoperable* *for the OPRM Upscale Function.

Alternative ly, the OPRM Upscale trip auto-enable setpoint(s) may be adjusted to place the channel in the enabled condftion (not-bypass ed). If the OPRM Upscale trip is placed in the enabled condition, the surveillanc e requirement is met and the channel is considered OPERABLE.

LIMERICK - UNIT 1 B 3/4 3-ld Amendment No. -l-7+,

Associated with Amendmen t~. 233

3/4.3 INSTRUMENTATION 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION (continued)

As noted in Table 4.3.1.1 -1, Note g, CHANNEL CALIBRATION for the APRM C

Simulated Thermal Power - Upscale Function 2.b and the OPRM Upscale Function 2.f, includes the recircu lation drive flow input function. The APRM Simulat ed Thermal Power - Upscale Function and the OPRM Upscale Function both require a valid flow signal. The APRM Simulated Thermal Power - Upscale Function uses drive drive flow to vary the trip setpoin t. The OPRM Upscale Function uses drive flow to automatically enable or bypass the OPRM Upscale trip output to RPS. A CHANNEL CALIBRATION of the APRM recircu lation drive fJow input function require calibra ting the drive flow transm itters and establi shing a valid drive sflow/

both core flow relation ship. The drive flow/ core flow relation ship is establis hed once per refuel cycle, while operating within 10% of rated core flow and within 10% of RATED THERMAL POWER. Plant operational experience has shown that flow correla tion methodology is consist ent with the guidance and intent inthis Reference 8. Changes throughout the cycle in the drive flow/ core flow relation ship due to the changing thermal hydraulic operating conditions of the core are accounted for in the margins included in the bases or analyse establi sh the setpoin ts for the APRM Simulated Thermal Power - Upscale s Functio used to n

and the OPRM Upstale Function.

For the Simulated Thermal Power - Upscale Function (Function 2.b), the CHANNEL CALIBRATION surveil lance requirement is modified by two Notes. The evaluation of channel performance for the condition where the as-founfirst d

Note requires setting channel setpoin t is outside its as-found tolerance but conservative with respectforto the Allowable Value. Evaluation of channel performance will verify that the channel willthe continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoin t methodology. The purpose -.,

ensure confidence in the channel performance prior to returning theof channel the assessment is to to service .

(

For channels determined to be OPERABLE but degraded, after returning the channel ..

service the performance of these channels will be evaluated under the plant Correct to Action Program. Entry into the Corrective Action Program will ensure required review ive documentation of the condition. The second Note requires that the as-left setting for and the channel be within the as-left tolerance of the Trip Setpoint. The as-left and as-found toleran ces, as applicable, will be applied to the surveil lance procedure setpoin t.

This will ensure that suffici ent margin to the Safety Limit and/or Analyti maintained. If the as-left channel setting cannot be returned to a settingcalwithin Limit is the as-left toleran ce of the Trip Setpoint, then the channel shall be declared inoperable.

The as-left tolerance for this function is calculated using the square-root-sum-of-squares of the reference accuracy and the measurement and test equipment error (includ readab ility). The as-found tolerance for this function is calculated using the square- ing root-sum-of-squares of the reference accuracy, instrument drift, and the measurement test equipment error (including readab ility). and To ensure that the APRMs are accura tely indicat ing the true core average power, the APRMs are adjuste d to the reactor power calcula ted from a heat balance if the heat balance calcula ted reactor power exceeds the APRM channel output by more than 2%

RTP.

This Survei llance does not preclude making APRM channel desired , when the heat balance calcula ted reactor power is lessadjustmthan ents, if the output. To provide close agreement between the APRM indicat ed power and APRM channel operati ng margin, the APRM channels are normally adjuste d to within +/- 2%to ofpreserv the e

heat balance calcula ted reactor power. However, this agreeme is not required OPERABILITY when APRM output indicat es a higher reactor power ntthan the heat for balance calcula ted reactor power. (.

~--

LIMERICK - UNIT 1 B 3/4 3-le Amendment No. -l-4+/-,-+/--7+,~.

Associated with Amend ment~. 233

3/4.3 INSTRUMENTATION BA

) 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION (continued)

As noted in Table 3.3.1-2, Not~"*", the redundant outputs from the 2-0ut-Of-4 Votir channel are considered part of the same channel, but the OPRM and APRM outputs are considered to be separate channels, so N = 8 to determine the interval between tests for application of Specification 4.3.1.3 (REACTOR PROTECTION SYSTEM RESPONSE TIME). The note further requires that testing of OPRM and APRM outputs shall be alternated.

Each test of an OPRM or APRM output tests each of the redundant outputs from the 2-0ut-Of-4 Voter channel for that function, and each of the corresponding relays in the RPS. Consequently, each of the RPS relays is tested every fourth cycle. This testing frequency is twic~ the frequency justified by References 2 and 3.

Automatic reactor trip upon receipt of a high-high radiation signal from the Main Steam Line Radiation Monitoring System was removed as the result of an analysis performed by General Electric in NED0-31400A. The NRC approved the results of this analysis as documented in the SER (letter to George J. Beck, BWR Owner's Group from A.C. Thadani, NRC, dated May 15, 1991i.

The measurement of response time at the frequencies specified,in the Surveillance Frequency Control Program provides assurance that the protective functions associated with each channel are completed within the time limit assumed in the safety analyses. No credit was taken for tho~e channels with response times indicated as not applicable except for the APRM Simulated Thermal Power - Upscale and Neutron Flux - Upscale tri~ functions and the OPRM Upscale trip function (Table 3.3.1-2, Items 2.b, 2.c, and 2.f). Response time may be demonstrated by any series of sequential, overlapping or total channel test measurement, provided such tests demrinstrate the total channel response time as defined. Sensor response time verification may be demonstrated by either (1) inplace, onsite or offsite test measurements, or (2) utilizing replacement sensors with certified response times.

Response time testing for the sensors as noted in Table 3.3.1-2 is not requ1red based on the analysis in NE00-32291-A. Response time testing for the remaining channel components is required as noted. For the digital electronic portions of the APRM functions, performan~e characteristics that determine response time are checked by a combination of automatic self-test, calibration activities, and response time tests, of the 2-0ut-Of-4 Voter (Table 3.3.1-2, Item 2.e).

J LIMERICK - UNIT 1 B 3/4 3-lf Amendment No. J.4.1.,-+/--7-7-,~,

Associated with Amendment~. 233

INSTRUMENTATION BASES 3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION (,,.

This specification ensures the effectiveness of the instrumentation used to mitigate the consequences of accidents by prescribing the OPERABILITY trip setpoints and response times for isolation of the reactor systems. When necessary, one channel may be inoperable for brief intervals to conduct required surveillance.

Surveillance intervals are determined in accordance with the Surveillance

.Frequency Control Program and maintenance outage times have been determined in accordance with NEDC-30851P, Supplement 2, "Technical Specification Improvement Analysis for BWR Instrumentation Common to RPS and ECCS Instrumentation" as approved by the NRC and documented in the NRC Safety Evaluation Report (SER)

(letter to D.N. Grace from C.E. Rossi dated January 6, 1989) and NEDC-31677P-A, "Technical Specification Improvement Analysis for BWR Isolation Actuation Instrumentation," as approved by the NRC and documented in the NRC SER (letter to S.D. Floyd from C.E. Rossi dated June 18, 1990).

Automatic closure of the MS!Vs upon receipt of a high-high radiation signal from the Main Steam Line Radiation Monitoring SYstem was removed as the result of an analysis Rerformed by General Electric in NED0-31400A. The NRC approved the results of this analysis as documented in the SER (letter to George J. Beck, BWR Owner's Group from A.C. Thadani, NRC, dated May 15, 199l).

Some of the trip settings may have tolerances explicitly stated where both the high and low values are ~ritical and may have a substantial effect on safety. The setpoints of other instrumentation, where only the high or low end of the settin9 ~ave a direct bearing on safety, are established at a level away from the normal operating range*to prevent inadvertent actuation of the systems involved. . * .

Except for the MS!Vs, the safety analysis does not address individual sensor response times or the response times of the logic systems to which the sensors are connected. For D.C. operated valves, a 3 second delay is assumed before the c:*

valve starts to move. For A.C. operated valves, it is assumed that the A.C.

power supply is lost and is restored by startup of the emergency diesel generators. In this event, a time of 13 seconds is assumed before the valve starts to move. In addition to the pipe break, the failure of the D.C. operated valve is assumed; thus the signal delay (sensor response) is concurrent with the 10-second diesel startup and the 3 second load center loading delay. The safety analysis considers an allowable inventory loss in each case which in turn determines the valve speed in conjunction with the 13-second delay. It follows that checking the valve speeds and the 13-second time for emergency power establishment will establish the response time for the isolation functions. .

Resronse time testing for sensors are not required based on the analysis in NEDO 3229 -A. Response time testing of the remaining channel components.is required as noted in Table 3.3.2-3.

• Operation with a trip set less conservative than its Trip Setpoint but within ,ts specified Allowable Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is an allowance for instrument drift specifically allocated for each trip in the safety analyses.

Primary containment isolation valves that are actuated by the isolation signals specified in Technical Specification Table 3.3.2-1 are identified in Technical Requirements Manual Table 3.6.3-1.

3/4.3.3 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION The emergency core cooling system actuation instrumentation is provided to initiate actions to mitigate the consequences of accidents that are beyond the ability of the operator to control. This specification provides the OPERABILITY requirements, trip setpo1nts and response times that will ensure effectiveness of the systems to provide the design protection. Although the instruments are c*** ...

listed by system, in some cases the same instrument may be used to send the __

actuation signal to more than one system at the same time.

LIMERICK - UNIT 1 B 3/4 3-2 Amendment No.~ -&-6,~,g.g..~,-l-4e. 186 1

INSTRUMENTATION BASES

)

3/4. 3. 3 EMERGENCY CORE COOLING ACTUATION INSTRUMENTATION (Continued)

Surveillance intervals are determined in accordance with the Surveitlance Frequency Control Program and maintenance outage times have been determined in accordance with NEDC-30936P, Parts 1 and 2. "Technical Specification Improvement Methodology (with Demonstration for BWR ECCS Actuation Instrumentati~n)," as apptoved by the NRC and documented in the SER (letter to D. N. Grace from A. C.

Thadani dated December 9~ 1988 (Part 1) and letter to D. N. Grace from C. E.

Rossi dated December 9, 1988 (Part 2)).

Successful operation of the required safety functions of the Emergency Core Cooling Systems (ECCS) is dependent upon the availability of adequate power for energizing various components such as pump motors, motor operated valves, and the assdciated control ~omponents. If the loss of power instrumentation detects that voltage levels are too low, the buses are disconnected from the offsite power sources and connected to the onsite diesel generator (DG) power sources. The loss of power relays in each channel have sufficient overlapping detection characteristics and functionality to permit operation subject to the conditions in Action Statement 37.* Bases 3/4.8.1, 3/4.8.2, and 3/4.8.3 provide discussion regarding parametric bounds for determining operability of the offsite sources.

Those Bases assume that the loss of power relays are *operable. With an inoperable 1272-llXOX relay, the grid voltage is monitored to 230kV (for the 101 Safeguard.

Bus Source) or 525kV (for the 201 Safeguard Bus Source) to increase the margin for the operation of the 127Z-11XOX relay.

Operation with a trip set less conservative than its Trip Setpoint but within its specified Allowable Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is an allowance for instrument drift specifically allocated for each trip in the safety analyses.

3/4,3.4.RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION The anticipated transient without scram*(ATWS) recirculation pump trip system provides a*means of limiting the consequences of the unlikely occurrence of a fai 1ure to sc:ram during an anticipated. transient. The response of the plant to.this postulated event falls within the envelope of study events in General Electric Company Topical Report NED0-10349, dated March 1971, NED0-24222, dated December 1979, and Section 15.8 of the FSAR.

The end~of-cycle recirculation pump trip (EOC-RPT) system*is a supplement to the reactor trip. During turbine trip and generator load rejection events, the EOC-RPT will reduce the likelihood of reactor vessel level decreasing to level

2. Each EOC-RPT system trips both recirculation pumps, reducing coolant flow in order to reduce the void collapse in the core during two of the most limiting pressurization events. The two events for which the EOC-RPT protective feature will function are closure of the turbine stop valves and fast closure of the turbine control valves.

A fast closure sensor from each of two turbine control valves provides input to the EOC-RPT system; a fast closure sensor from each of the other two turbine control valves provides input to the second EOC-RPT system. Similarly, a*

position switch for each of two turbine stop valves provides input to one EOC-

-~-

RPT system; a position switch from each of the other two stop valves provides input to the other EOC-RPT system. For each EOC-RPT system, the sensor relay contacts are arranged to form a 2-out-of-2 logic for the fast closure of turbine control valves and a 2-out-of-2 logic for the turbine stop valves. The operation of either logic will actuate the EOC-RPT system and trip both recirculation pumps.

INSTRUMENTATION

=B_As_E_s_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ <C 3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION (Continued)

Each EOC-RPT system may be manually bypassed by use of a keyswitch which is administratively controlled. The manual bypasses and the automatic Operating Bypass at less than 29.5% of RATED THERMAL POWER are annunciated in the control room.

The EOC-RPT system response time is the time assumed in the analysis between initiation of valve motion and complete suppression of the electric arc, i.e.,

175 ms. Included in this time are: the*response time of the sensor, the time allotted for breaker arc suppressi~n. and the response time of the system logic.

LIMERICK - UNIT 1 B 3/4 3-3a Amendment No.~.

Associated with Amendment 201

INSTRUMENTATION

) 3/4.~.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTAT_ION (Continued)

Surveillance intervals are determined in accordance with the Surveillance Frequency Control Program and maintenance outage times have been determined in accordance with GENE-770-06-1, "Bases for Changes to Surveillance Test Intervals and

• Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications," as approved by the NRC and documented in the SER (letter to R.D. Binz, IV, from C.E. Rossi dated Julyi21, 1992).

Operation with a trip set less conservative than its Trip Setpoint but within its specified Allowable Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is an allowance for instrument drift specifically allocated for each trip in the safety analyses.

3/4.3.5 REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION The reactor core isolation cooling system actuation instrumentation is provided to initiate actions.to assure adequate core cooling in the event of reactor isolation from its primary heat sink and the loss of feedwater flow to the reactor vessel. This instrumentation does not provide actuation of any of the emergency core cooling equipment.

Surveillance intervals are determined in accordance with the Surveillance Frequency Control Program and maintenance outage times have been specified in accordance with recommendations made by GE in their letter to the BWR Owner's Group dated August 7, 1989,

SUBJECT:

"Clarification of Technical Specification changes given in ECCS Actuation Instrumentation Analysis."

Operation with a trip set less conservative than its Trip Setpoint but within its specified Allowable Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is an allowance for instrument drift specifically allocated for each trip in the safety analyses.

3/4.3.6 CONTROL ROD BLOCK INSTRUMENTATION The control rod block.functions are provided consistent with the requirements of the specifications in Section 3/4.1.4, Control Rod Program Controls and Section 3/4.2 Power Distribution Limits and Section 3/4.3 Instrumentation. The trip logic is arranged so that a trip in any one of the inputs will result in a control rod block.

Surveillance intervals are determined in accordance with the Surveillance Frequency Control Program and maintenance outage times have been determined in accordance with NEDC-30851P, Supplement 1, "Technical Specification Improvement Analysis for BWR Control Rod Block Instrumentation," as approved by the NRC and documented in the SER (letter to D. N. Grace from C. E. Rossi dated September 22, 1988).

Operation with a trip set less conservative than its Trip Setpoint but within its specified Allowable Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is an allowance for instrument drift specifically allocated for each trip in the safety ana 1yses.

LIMERICK - UNIT 1 B 3/4 3-4 Amendment No. 4-S, ** Q., 186

INTENTIONALLY LEFT BLANK (l

INSTRUMENTATION BASES 3/4,3,7 MONITORING INSTRUMENTATION 3/4,3,7.1 RADIATION MONITORING INSTRUMENTATION The OPERABILITY of the radiation monitoring instrumentation ensures that:

Cl) the radiation levels are continually measured in the areas served by the 1ndividual channels, and (2) the alarm or automatic action is initiated when the radiation level trip setpoint is exceeded, and (3) sufficient information is*

available on selected plant parameters to monitor and assess these variables following an accident. This capability is consistent with 10 CFR Part 50, Appendi~ A, General Design Criteria 19, 41, 60, 61, 63, and 64.

The surveiilance interval for the Main Control Room Norm&l Fresh Air Supply Radiation Monitor is determined in accordance with the Surveillance Frequency Control Program.

3/4,3,7,2 (Deleted) - INFORMATION FROM THIS SECTION RELOCATED TO THE UFSAR.

3/4,3,7.3 (Deleted) - INFORMATION FROM THIS SECTION RELOCATED TO THE ODCM.

3/4,3.7.4 REMOTE SHUTDOWN SYSTEM INSTRUMENTATION AND CONTROLS The OPERABILITY of the remote shutdown system instrumentation and controls ensures that sufficient capability is available to permit shutdown and maintenance of HOT SHUTDOWN of the unit from locations outside of the control room. This capability is required in the event control room habitability is lost and is consistent with General Design Criterion 19 of 10 CFR Part 50, Appendix A.

3/4,3.7.5 ACCIDENT MONITORING INSTRUMENTATION The OPERABILITY of the accident monitoring instrumentation ensures that sufficient information is available on selected plant parameters to monitor and assess important variables following an accident. This capability is consistent with the recommendations of Regulatory Guide 1.97, "Instrumentation for Light Water Cooled Nuclear Power Plants to Assess Plant Conditions During and Following an Accident,"

December 1975 and NUREG-0737, "Cl arifi cation of TMI Action Pl an Requirements,"

November 1980.

Table 3~3.7.5-1, Accident Monitoring Instrumentation, Item 2, requires two OPERABLE channels of Reactor Vessel Water Level monitoring from each of two overlapping instrumentation loops to ensure monitoring of Reactor Vessel Water Level over the range of -350 inches to +60 inches. Each channel is comprised of one OPERABLE Wide Range Level instrument loop (-150 inches to +60 inches) and one OPERABLE Fuel Zone Range instrument loop (-350 inches to -100 inches). Both instrument loops, Wide Range and Fuel Zone Range, are required by Tech. Spec. 3.3.7.5 to provide sufficient overlap to bound the required range as described in UFSAR Section 7.5.

Action 80 is applicable if the required number of instrument loops per channel (Wide Range and Fuel Zone Range) is not maintained.

LIMERICK - UNIT 1 B 3/4 3-5 Amendment No. A-g,~.~.~.~.

[CR 02 00470,-+/-+J ,~. ECR LG 09-00585

INSTRUMENTATION BASES 3/4.3.7.5 ACCIDENT MONITORING INSTRUMENTATION (continued)

Table J.3.7.5-1, Accident Monitoring Instrumentation, Item 13, requires two OPERABLE channels of Neutron Flux monitoring from each of three overlapping instrumentation loops to ensure monitoring of Neutron Flux over the 9range of3 10" 6% to 100% full power. Each channel is comprised of one OPERABLE SRM (10* % to 10* % power),

one OPERABLE !RM (10" 4% to 40% power) and one OPERABLE APRM (0% to 125% power). All three instrument loops, SRM, !RM and APRM, are required by Tech. Spec. 3.3.7.5 to provide sufficient overlap to bound the required range as described in UFSAR Section 7.5. Action 80 is applicable if the required number of instrument loops per channel (SRM, IRM, and APRM) is not maintained.

3/4.3.7.6 SOURCE RANGE MONITORS The source range monitors provide the operator with information of the status of the neutron level in the core at very low power levels during startup and shutdown.

At these power levels, reactivity additions shall not be made without this flux level information available to the operator. When the intermediate range monitors are on scale, adequate information is available without the SRMs and they can be retracted.

LIMERICK - UNIT 1 B 3/4 3-5a Amendment No. 48,~.+G,-7-&,~

ECR LG 09-00585

-~---- ------ .

INSTRUMENTATION

)

314.3.7.7 (Deleted) - IJiEGRMAUDlLIRillLI.l::LlS_--5.ECTION RELOCATED TO THE TRM.

3/4.3.7.8 CHLORINE AND TOXIC GAS DETECTION SYSTEMS The OPERABILITY of the chlorine and toxic gas detection systems ensures that an accidental chlorine and/or toxic gas release will be detected promptly and the necessary protective actions will be automatically initiated for chlo-rine and manually initiated for toxic gas to provide protection for control room personnel. Upon detection of a high concentration of chlorine, the control room emergency ventilation system will automatically be placed in the chlorine isol~tion mode of operation to provide the required protection. Upon detection of a high concentration of toxic gas, the control room emergency ventilation system will manually be placed in the chlorine isolation mode of operation to provide the required protection. The detection systems required by this speci-fication are consistent with the recommendations of Regulatory Guide 1.95, "Pro-tection of Nuclear Power Plant Control Room Operators against an Accidental Chlorine Release," February 1975.

There are three toxic gas detection subsystems. The high toxic chemical concentration alarm in the Main Control Room annunciates when two of the three subsystems detect a high toxic gas concentration. An Operate/Inop keylock switch is provided for each subsystem which allows an individual subsystem to be placed in the tripped condition. Placing the keylock switch in the INOP position initiates one of the two inputs required to initiate the alarm in the Main Control Room.

Surveillance intervals are determined in accordance with the Surveillance Frequency Control Program and maintenance outage times have been determined in accordanc~ with GENE-770-06-1, "Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications.," as approved by the NRC and documented in the SER (letter to R.D.

Binz, IV, from C.E. Rossi dated July 21, 1992).

3/4.3.7.9 (Deleted) - INFORMATION FROM THIS SECTION RELOCATED TO THE TRM.

LIMERICK - UNIT 1 B 3/4 3-6 Amendment No. 48-,W,+G-,&4,-W-4,-+/--+/--7, 186

. ct (INTENTIONALLY LEFT BLANK) cc

INSTRUMENTATION BASE 3/4.3.7.10 (Deleted) 3/4.3.7.11 (Deleted) - INFORMATION FROM THIS SECTION RELOCATED TO THE ODCM.

3/4.3.7.12 (Deleted) - INFORMATION FROM THIS SECTION RELOCATED TO THE ODCM AND THE TRM.

3/4.3.8 * (Deleted) - INFORMATION FROM THIS SECTION RELOCATED TO THE UFSAR.

3/4.3.9 FEEDWATER/MAIN TURBINE TRIP SYSTEM ACTUATION INSTRUMENTATION The feedwater/main turbine trip system actuation instrumentat ion is provided to initiate action of the feedwater system/main turbine trip system in the event of failure of feedwater controller under maximum demand.

REFERENCES:

1. NEDC-30851P-A, "Technical Specificatio n Improvement Analyses for BWR Reactor Protection System," March 1988.

2. NEDC-32410P-A, "Nuclear Measurement Analysis and Control Power

~ Range Neutron Monitor CNUMAC PRNM) Retrofit Plus Option III Stability Trip Function," October 1995.

3. NEDC-32410P-A, Supplement 1, "Nuclear Measurement Analysis and Control Power Range Neutron Monitor (NUMAC PRNM) Retrofit Plus Option III Stability Trip Function," November 1997.

4. NED0-31960~A, "BWR Owners' Group Long-Term Stability Solutions Licensing Methodology," November 1995.

5. NED0-31960-A, SupplemeDt 1, "BWR Owners' Group Long-Term Stability Solutions Licensing Methodology," November 1995.

6. NED0-32465-A, "Reactor Stability Detect and Suppress Solutions Licensing Basis Methodology for Reload Application s," August 1996.

7. Letter, L. A. Engla~d (BWROG) to M. J. Virgilio, "BWR Owners' Group Guidelines for Stability Interim Corrective Action," June 6, 1994.

8. GE Service Information Letter No. 516, "Core Flow Measurement - GE BWR/3 , 4 , 5 and 6 Pl ants , " Jul y 26 , 19 9O.

9. GE Letter NSA 00-433, Alan Chung (GE) to Sujit Chakraborty (GE),

"Minimum Number of Operable OPRM Cells for Option III Stability at Limerick 1 & 2," May 02, 2001.

LIMERICK - UNIT 1 B 3/4 3-7 Amendment No. JJ., 4-&, ::/-fJ,

~ . G4, ~ . 7+, 228

Wide Range Level This Indication Is reactor coolant le11peralure sensitive. The

,- calibr ation Is lhus made al rated conditions. The level error

....X at low pressures (leape r1ture s) Is bounded by the safely 1n1lysts

0 which reflec ts the weight-of-cool1nl *hove the lower tap, and not Indicated level.

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Al?RH - A.PRM 3 APRH 2 Al?RH 4 Al?RM .:..PRH Al?RM APRH 2-0UT-O.:-~  :-O!.!T-OE'"-4  :?-OUT-OE'"-4 2-0lJT-OF-4 VOTER r.l VOTER A2 VOTER Bl VOTER B2

'I' Rl?S CHANNE!. i\l RE'S CHANNEL .:..z RPS CHANNEL Bl RPS CHFINNEL 92 RELAYS Kl2~ ~ ~Ll£ RELAYS Kl2C & KlZG RELAYS Kl2B & Kl2f RE:i.AYS Kl2D & Kl2H BASES FIGtmE B 3/4.3-2 APm! CONFIGURATION APR ! 2 ZOllfJ LIMERICK - UNIT l . 3 3/ 4 3-9 Amendment No. 141

(INTENTIONALLY LEFT BLANK)

. ~. *. '*

3/4.4.REACTOR COOLANT SYSTEM

')

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'-~-4--;-4--;-l-REC-+R-C----l:J-!:-A+I-8N--S-¥-s-T-EM>-----

The impact of single recirculation loop operation upon plant safety is assessed and shows that single-loop operation is permitted if the MCPR fuel cladding safety limit is increased as noted by Specification 2.1.2, APRM scram and control rod block setpoints are adjusted as noted in Tables 2.2.1-1 and 3.3.6-2, respectively.

An inoperable jet pump is not, in itself, a sufficient reason to declare a recirculation loop inoperable, but it does, in case of a design-basis-acc ident, increase the blowdown area and reduce the capability of reflooding the core; thus, the requirement for shutdown of the facility with a jet pump inoperable. Jet pump failure can be detected by monitoring jet pump performance on a prescribed schedule for significant degradation.

Additionally, surveillance on the pump speed of the operating recirculation loop is imposed to exclude the possibility of excessive internals vibration.

The surveillance on differential temperatures below 30% RATED THERMAL POWER or 50% rated recirculation loop flow is to mitigate the undue thermal stress on vessel nozzles, recirculation pump and vessel bottom head during the extended operation of the single recirculation loop mode.

Surveillance of recirculation loop flow, total core flow, and diffuser-to--

lower plenum differential pressure is designed to detect significant degradation in jet pump performance that precedes jet pump failure. This surveillance is required to be performed only when the loop has forced recirculation flow since surveillance checks and measurements can only be performed during jet pump operation. The jet pump failure of concern is a complete mixer displacement due to jet pump beam failure. Jet pump plugging is also of concern since it adds flow resistance to the recirculation loop. Significant degradation is indicated if the specified criteria confirm unacceptable deviations from established patterns or relationships. Since refueling activities (fuel assembly replacement or shuffle, as well as any modifications to fuel support orifice size or core plate bypass flow) can affect the relationship between core flow, jet pump flow, and recirculation loop flow, these relationships may need to be re-established each cycle. Similarly, initial entry into extended single loop operation may also require establishment of these relationships. During the initial weeks of operation under such conditions, while base-lining new "established patterns," engineering judgment of the daily surveillance results is used to detect significant abnormalities which could indicate a jet pump failure.

The recirculation pump speed operating characteristics (pump flow and loop flow versus pump speed) are determined by the flow resistance from the loop suction through the jet pump nozzles. A change in the relationship indicates a plug, flow restriction, loss in pump hydraulic performance, leakage, or new flow path between the recirculation pump discharge and jet pump nozzle. For this criterion, the pump flow and loop flnw versus pump speed relationship must be verified.

LIMERICK - UNIT 1 B 3/4 4-1 Amendment No. ~.~.-+/-+-7.

Associated with Amendment 196

REACTOR COOLANT SYSTEM 3/4.4.1 RECIRCULATION SYSTEM (continued)

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

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

Recirculation pump speed mismatch limits are in compliance with the ECCS LOCA analysis design criteria for two recirculation loop operation. The limits will ensure an adequate core flow coastdown from either recirculation loop following a LOCA. In the case where the mismatch limits cannot be maintained during two loop operation, continued operation is permitted in a single recir-culation loop mode.

In cider to prevent undue streis on the vessel nozzles and bottom head region, the reci rcul at ion 1oop temperatures sha 11 be within 50° F of each other prior to ((~,

startup of an idl~ loop. The loop temperature must also be within 50°F of the ~-*

reactor pressure vessel coolant temperature to prevent thermal shock to the recirculation pump and-recirculation nozzles. Sudden equalization of a temperature difference> 145°F between the reactor vessel bottom head coolant and the coolant in the upper region of the reactor vessel by increasing core flow rate would cause undue stress in the reactor vessel bottom head.

3/4.4.2 SAFETY/RELIEF VALVES The iifety valve function of the safety/relief valves operates to prevent the reactor coolant system from being pressurized above the Safety Limit of 1325 psig in accordance with the ASME Code. A total of 12 OPERABLE safety/

relief valves is required to limit reactor pressure to within ASME III allow-able values for the worst case upset transient.

Demonstration of the safety/relief valve lift settings will occur only during shutdown. The safety/relief valves will be removed and either set pressure tested or replaced with spares which have been previously set pres-sure tested and stored in accordance with manufacturers recommendations at the frequency specified in the Surveillance Frequency Control Program.

Correste~ ~Y Ltr. gate~ 3/10/00 LIMERICK - UNIT 1 B 3/4 4-2 Amendment No. d0,ld7,+7-7,.}.ge Associated with Amendme~t 196

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REACTOR COOLANT SYSTEM

) 3/4.4.3 REACTOR COOLANT SYSTEM LEAKAGE 3/4.4.3.1 LEAKAGE DETECTION SYSTEMS BACKGROUND UFSAR Safety Design Basis (Ref. 1), requires means for detecting and, to the extent practical, identifying the location of th~ source of R~a~tor Coolant System (~CS)

PRESSURE BOUNDARY LEAKAGE. Regulatory Guide 1.45, Revision 0, (Ref. 2) describes acceptable methods for selecting leakage detection systems.

Limits on leakage from the reactor coolant pressure boundary (RCPB) are required so that appropriate action can be taken before the _integrity of the RCPB is impaired (Ref.

2). Leakage detection systems for the RCS are provided to alert the operators when leaka9e rates above normal. background levels are detected and also to supply .

• quantitative measurement of leakage rates~ In addition to meeting the OPERABILITY requirements, the monitors are typically set to provide the most sensitive response without causing an *excessi~e number of spurious alarms.

• Systems for quantifying the leakage are necessary to provide prompt and quantitative information to the operators to permit them to take immediate corrective- action.

Leakage from the RCPB inside the drywell is detected by at least cine of four (4) independently monitored variables which include drywell sump flow monitoring eguipment with the required RCS leakage detection instrumentation (i.e., the drywell floor drain sump flow*monitoring system, or, the drywell equipment drain sump

• monitoring system with the drywell floor drain sump overflowing to the drywell egui pment drain sump), drywell gaseous radioactivity, drywell unit cool er condensate flow rate and drywell pressure/temperature levels. The primary means of quantifying leakage in the drywell is the drywell sump monitoring system for UNIDENTIFIED LEAKAGE and the drywell equipment drain tank flow monitoring system for IDENTIFIED LEAKAGE.

IDENTIFIED leakage is not germane to this Tech Spec and the associated drywell equipment drain tank flow monitoring system is not included * .

. l

~ The drywell floor drain sump flow monitoring system monitors UNIDENTIFIED LEAkAGE collected in the floor drain sump. UNIDENTIFIED LEAKAGE consists of leakage from RCPB components inside the drywell which are not normally subject to leakage and otherwise routed to the drywell equipment drain sump. The primary containment floor drain sump has transmitters th~t su~ply level indication to the main control roo~ via the plant

• monitoring system. The floor-drain sump level transmitters are associated with High/Low level switches that open/~ose the* sump tank drain valves automatically. The level instrument processing unit calculates an* average leak rate (gpm) for a given.

• measurement period which resets whenever the sump drain.valve closes. The level processing unit provides an alarm to the main control room each time the average leak rate changes by a predetermined value since the last time the alarm was reset. For the

.drywell floor drain sump flow monitoring system, the setpoint basis is a 1 gpm change*

in.UNIDENTIFIED LEAKAGE. . * .

AA alternate to.the drywell floor drain sump flow. monitoring system for- quantifying.

UNIDENTIFIED LEAK~GE is trye drywell ~quipment drain sump m9nitoring ~ystem, if the .

drywell floor*drain sump is overflpw1ng to the-drywell equipment drain sump. In this configuration, the drywell equipment drain sump collects all leakage into the drywell equipment drain sump and the overflow from the drywel 1 fl o.or drain sump. Therefore, if the drywell floor drain sµmp is overflowing to the drywell equipment drain sump, the drywell equipment drain sump monitoring system can be used to quantify

.UNIDENTIFIED LEAKAGE. In this condition, all leakage measured by the drywell equipment drain sump monitoring system is assumed to be UNIDENTIFIED LEAKAGE. The leakage determination process, *including the transition to and use of the alternate method is described in station procedures. The alternate method would only be used when the drywell floor drain sump flow monitoring system is unavailable.

In addition to the drywell sump monitoring system described above, the discharge of each sump is monitorea by an independent flow element. The measured flow rate from the flow element is integrated and recorded. A main control room alarm is also provided to indicate an excessive sump discharge rate measured via the flow element.

This system, referred to as the "drywell floor drain flow totalizer", is not credited

~ for drywell floor drain sump flow monito,ring system operability.

• LIMERICK - UNIT 1 B 3/4 4-3 Amendment No. 4-Q, 49-, ~ .

Associated with Amendment No.~. 208

REACTOR COOLANT SYSTEM BACKGROUND (Continued)

The primary containment atmospheric gaseous radioactivity monitoring system continuously monitors the primary containment atmosphere for gaseous radioactivity levels. A sudden increase of radioactivity, which may be attributed to RCPB steam or reactor water leakage, is annunciated in the main control room.

Condensate from the eight drywell air coolers is routed to the drywell floor drain sump and is monitored by a series of flow transmitters that provide indication and alarms in the main control room. The outputs from the flow transmitters are added together by summing units to provide a total continuous condensate drain flow rate. The high flow alarm setpoint is based on condensate*drain flow rate in excess of 1 gpm over the currently identified preset leak rate. The drywell air cooler condensate flow rate monitoring system serves as an added indicator, but not quantifier, of RCS UNIDENTIFIED LEAKAGE (Ref. 4).

The drywell temperature and pressure monitoring systems provide an indirect method for detecting RCPB leakage. A temperature and/or pressure rise in the drywell above normal levels may be indicative of a reactor coolant or steam leakage (Ref. 5).

APPLICABLE SAFETY ANALYSES A threat of significant compromise to the RCPB exists if the barrier contains a crack that is large enough to propagate rapidly. Leakage rate limits are set low enough to detect the leakage emitted from a single crack in the RCPB (Refs. 6 and 7).

A control room alarm allows the operators to evaluate the significance of the indicated leakage and, if necessary shut down the reactor for further investigation and corrective action. The ailowed leakage rates are well below.the rates predicted for critical crack sizes (Ref. 7). *Therefore, these actions provide adequate responses before a significant break in the RCPB can occur.

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

LIMITING CONDITION FOR OPERATION CLCO)

This LCO requires instruments of diverse monitoring principles to be OPERABLE to provide confidence that small amounts of UNIDENTIFIED LEAKAGE are detected in time to allow actions to place the plant in a safe condition, when RCS leakage indicates possible RCPB degradation.

The LCD requires four instruments to be OPERABLE.

The required instrumentation to quantify UNIDENTIFIED LEAKAGE from the RCS consists of either the drywell floor drain sump flow monitoring system, or, the drywell equipment drain sump monitoring system with the drywell *floor drain sump overflowing to the drywell equipment drain sump. For either system to be considered operable, the flow monitoring portion of the system must be operable. The identification of an increase in UNIDENTIFIED LEAKAGE will be delayed by the time required for the UNIDENTIFIED LEAKAGE to travel to the drywell floor drain sump and it may take longer than one hour to detect a 1 gpm increase in UNIDENTIFIED LEAKAGE, depending on the origin and magnitude Of the leakage. This sensitivity is acceptable for containment sump monitor OPERABILITY.

The reactor coolant contains radioactivity that, when released to the primary containment, can be detected by the gaseous primary containment atmosRheric radioactivity monitor. A radioactivity detection system is included for monitoring gaseous activities because of its sens1t1vity and rapid response to RCS leakage, but it has recognized limitations. Reactor coolant radioactivity levels will be low during initial reactor startup and for a few weeks thereafter, until activated corrosion * -

products have been formed and fission products apRear from fuel element cladding (,(_*

contamination or cladding defects. If there are few fuel element cladding defects and ~--

low levels of activation products, it may not be possible for the gaseous primary LIMERICK - UNIT 1 B 3/4 4-3a Amendment No.~.

Associated with Amendment No.~. 208

REACTOR COOLANT SYSTEM

~

Y LIMITING CONDITION FOR OPERATION C LCD) (Continued) containment atmospheric .radioactivity monitor to detect a 1 gpm increase within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> during normal operation. However,* the gaseous primary containment atmospheri~

radioactivity monitor is OPERABLE when it is capable of detecting a 1 gpm increase in UNIDENTIFIED LEAKAGE within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> given an RCS activity equivalent to that assumed in the design calculations for the monitors (Reference 9).

The LCO is satisfied when monitors of diverse measurement means are available. Thus, the drywell floor drain sump monitoring system*in combination with a gasecius primary

. containment atmospherit radioactivity-monitor, .a primary containment air cooler condensate flow rate monitoring system, and a primary containment pressure and temperature monitoring system provides an acceptable minimum.

APPLICABILITY In OPERATIONAL CONDITIONS l, 2, and 3, leakage detection systems are required to be OPERABLE to support lCO 3.4.3.2. This applicability is consistent with that for LCO 3.4.3.2.

ACTIONS A. With the primary containment atmosphere gaseous monitoring system inoperable, grab samples of the primary containment .atmosphere must be taken and analyzed to provide periodic leakage information. [Provided a sample is obtained and analyzed once every 12 *hours, the plant may be operated for up to 30 days to allow restoration of the radioactivity monitoring system. The plant may continue operation since other forms

) of drywel1 lea_kage detection are available.]

The 12 hour-interval provides periodic information that is adequate to detect leakage. The 30 day Completion Time for Restoration recognizes other forms of leakage detection are available.

• B. With required dryweli sump monitoring system inoperable, no other form of sampling can provide the equivalent information to quan.tify 1eakage at the required 1 gpm/hour sensitivity. However, the* primary containment atmospheric gaseous monitor

[and the primary containment air cooler condensate flow rate monitor] will provide indication of changes in leakage.

With required drywell sump monitoring system inoperable, drywell condensate flow rate monitoring frequency increased from 12 to every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, and UNIDENTIFIED LEAKAGE and total Teakage being-determined every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> (Ref. SR 4.4.3.2.1.b) operation may continue for 30 days.* To the extent practical, the surveillance frequency change associated with the drywell condensate flow rate monitoring system, makes up for the loss-of the drywell floor drain monitoring system which had a normal surveillance requirement to monitor- leakage every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. Also note that in this instance, the drywell floor drain tank flow totalizer will be used to comply

• with SR 4.4.3.2.1.b. The 30 day Completion Time of the required ACTION is acceptable, based on operating experience, considering the multiple forms of leakage detection that are still available.

C. With the required primary containment air cooler condensate flow rate monitoring system inoperable, SR 4.4.3.1.a must be performed every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> to provide periodic information of activity in the primary containment of more rrequent interval than the routine frequency of every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> interval provides periodic information that is adequate to detect leakage and recognizes that other forms of leakage detection are available. The required ACTION has been clarified to state LIMERICK - UNIT 1 B 3/4 4-3b Amendment No. -!4-Q.,~.

Associated with Amendment No . .W.S., 208

REACTOR COOLANT SYSTEM ACTIONS (Continued) that the additional surveillance requirement is not applicable if the required primary containment atmosphere gaseous radioactivity monitoring system is also inoperable. Consistent with SR 4.0.3, surveillances are not required to be performed on inoperable equipment. In this case, ACTION Statement A. and E, requirements apply.

D. With the primary containment pressure and temperature monitoring system inoperable, operation may continue for up to 30 days given the system's indirect capability to detect RCS leakage. However, other more limiting Tech Spec requirements associated with the primary containment pressure/temperature monitoring system will still apply.

E. With both the primary containment atmosphere gaseous radioactivity monitor and the primary containment air cooler condensate flow rate monitor inoperable, the only means of detecting leakage is the drywell floor drain sump monitor and the drywell.

pressure/temperature instrumentation. This condition does not provide the required diverse means of leakage detection. The required ACTION is to restore either of the inoperable monitors to OPERABLE status within 30 days to regain the intended leakage detection diversity. The 30 day Completion Time ensures that the plant will not be operated in a degraded configuration for a lengthy time period. While the primary containment atmosphere gaseous radioactivity monitor is INOPERABLE, primary containment atmospheric grab samples will be taken and analyzed every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> since ACTION Statement A. requirements also apply.

F. With the drywell floor drain sump monitoring system inoperable and the drywell unit coolers condensate flow rate monitoring system inoperable, one of the two remaining means of detecting leakage is the primary containment atmospheric gaseous radiation C

monitor. The primary containment atmospheric gaseous radiation monitor typically cannot detect a 1 gpm leak within one hour when RCS activity is low. Indirect methods of monitoring RCS leakage must be implemented. Grab samples of the primary containment atmosphere must be taken and analyzed and monitoring of RCS leakage by administrative means must be performed every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to provide alternate periodic information.

Administrative means of monitoring RCS leakage include monitoring and trending parameters that may indicate an increase in RCS leakage. There are diverse alternative mechanisms from which appropriate indicators may be selected based on plant conditions. It is not necessary to utilize all of these methods, but a method or methods should be selected considering the current plant conditions and historical or expected sources of UNIDENTIFIED LEAKAGE. The administrative methods are the drywell cooling fan inlet/outlet temperatures, drywell equipment drain sump temperature indicator, drywell equipment drain tank hi temperature indic~tor, and drywell equipment drain tank flow indicator. These indications, coupled with the atmospheric grab samples, are sufficient to alert the operating staff to an unexpected increase in UNIDENTIFIED LEAKAGE.

In addition to the primary containment atmospheric gaseous radiation monitor and indirect methods of monitoring RCS leakage, the primary containment pressure and temperature monitoring system is also available to alert the operating staff to an unexpected increase in UNIDENTIFIED LEAKAGE.

LIMERICK - UNIT 1 B 3/4 4-3c Amendment No.~~9,.1-&6 Associated with Amendment No. 205

REACTOR COOLANT SYSTEM BAE

~-~~ ACTIONS (Continued)

The 12 h6ur i*nterval ts sufficient to-detect increasing Res, leakage. The Required Action provides 7 days to restore another RCS leakage monitor to OPERABLE status to regairi* the intended' leakage detection diversity .. The 7-day Completion Time ensure~ that the plaht will not be~opejated iri a degr~ded cb~figuratiori for a lengthy time . . period;

~ .*

G. If any required AtTION of Condittbni A,~; C, D, E or*F-cannot be met.within the associ cifed Compl_eti on Time, the* pl ant mµst be bro"ught to an. OPERATIONAL CONDITION in which the LCO does _not apply.* Tei achieve this status, the plant must be brought to at least HOT. SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> a~d,,COLD SHUTDOWN within the riext 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Th~ allo~ed Completion Time~ are reasonable, based 6n *opetating experience, to perf6rm the ACTIONS in an orderly manner and without challenging plant systems~

SURVEILLANtE REQUIREMENTS SR 4.4.3.1.a This SR is for the performance of a CHANNEL CHECK of the required primary containment atmospheric monitoring system. The check gives reasonable confidence that the channel is operating properly.

SR 4.4'.3.l.b This SR is for the performance of a CHANNEL FUNCTIONAL TEST of the required* RCS 1eakage detection instrumentation. The test ensures that the monitors can perform their

~ function in the desired manner. The test also verifies the alarm setpoint and relative

~ accuracy of the instrument string.

SR 4.4.3.1.c The SR is for the performance of a CHANNEL CALIBRATION of required 1eakage detection instrumentation channels. The calibration verifies the accuracY.,.,_Qf the instrument string, including the instruments located inside containment.*-*

SR 4 .'4. 3 .1. d This SR provides a routine check of primary containment pressure and temperature for indirect evidence of RCS leakage.

REFERENCES

1. LGS UFSAR, Section 5.2.5.1.

2. Regulatory Guide 1.45, Revision 0, "Reactor Coolant Pressure Boundary Leakage Detection Systems," May 1973.

3. LGS UFSAR, Section 5.2.5.2.1.3.

4. LGS UFSAR, Section 5.2.5.2.1.4.

5. LGS UFSAR, Section 5.2.5.2.1.1(2).

6. GEAP-5620, April 1968

7. NUREG-75/067, October 1975.

8. LGS UFSAR, Section 5.2.5.6.

9. LGS UFSAR, Section 5.2.5.2.1.5 J

LIMERICK - UNIT 1 B 3/4 4-3d Amendment No. J.4G.,~.

Associated with Amendment No. 205

REACTOR COOLANT SYSTEM 3/4.4.3.2 OPERATIONAL LEAKAGE The allowable leakage rates from the reactor coolant system have been based on the predicted and experimentally observed behavior of cracks in pipes. The normally expected background leakage due to equipment design and the detection capability of the instrumentation for determining system leakage was also considered. The evidence obtained from experiments suggests that for leakage somewhat greater.than that specified for UNIDENTIFIED LEAKAGE the probability is small that the imperfection or crack associated with such leakage would grow rapidly. However, in all cases, if the leakage rates exceed the values specified or the leakage is located and known to be PRESSURE BOUNDARY LEAKAGE, the reactor will be sh~tdown to allow further investigation and corrective action. The limit of 2 gpm increase in UNIDENTIFIED LEAKAGE over a 24-hour period and the monitoring of qrywell floor drain sump and drywell equipment drain tank flow rate at least once every eight (8) hours conforms with NRC staff positions specified in NRC Generic Letter 88-01, "NRC Position on IGSCC in BWR Austenitic Stainless Steel Piping," as revised by NRC Safety Evaluation dated March 6, 1990. The ACTION requirement for the 2 gpm.increase in UNIDENTIFIED LEAKAGE limit ensures that such leakage is identified or a plant shutdown is initiated to allow further investigation and corrective action. Once identified, reactor operation may continue dependent upon the impact on total leakage.

The function of Rea~tor Coolant System Pressure Isolation Val~es (PIVs) is to separate the high pressure Reactor Coolant System from an attached low pressure system.

The ACTION requirements for pressure isolation valves are used in conjunction with the system specifications for which PIVs are listed in the Technical Requirements Manual and with primary containment isolation valve requirements to ensure that plant operation is appropriately limited.

(i---..

The Surveillan*ce Requirements for the RCS pressure isolation valves provide added ~*

assurance of valve integrity thereby reducing the probability of gross valve failure and consequent intersystem LOCA. Leakage from the RCS pressure isolation valves is not included in any other allowable operational leakage specified in Section 3.4.3.2.

3/4.4.4 (Deleted) INFORMATION FROM THIS SECTION RELOCATED TO THE TRM LIMERICK - UNIT 1 B 3/4 4-3e Amendment No. -140,~,+74.~.

Associated with Amendment No. 205

REACTOR COOLANT SYSTEM BASES 3/4.4.4 (Deleted) INFORMATION FROM THIS SECTION RELOCATED TO THE TRM 3/4.4.5 SPECIFIC ACTIVITY The limitations on the specific activity of the primary coolant ensure that the 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> thyroid and whole body doses resulting from a main steam line failure outside the containment during steady state operation will not exceed small fractions of the dose guidelines of 10 CFR Part 100. The values for the limits on specific activity represent interim limits based upon a parametric evaluation by the* NRC of typical site locations. These values are conservative in that specific site parameters, such as SITE BOUNDARY location and meteorological conditions, were not considered in this evaluation.

The ACTION statement permitting POWER OPERATION to continue for limited time periods with the primary coolant's specific activity greater than 0.2 microcurie per gram DOSE EQUIVALENT I-131, but less than or equal to 4 microcuries per gram DOSE EQUIVALENT I-131, accommodates possible iodine spiking phenomenon which may occur following changes in the THERMAL POWER. This action is modified by a Note that permits the use of the provisions of Specificatio n 3.0.4.c. This allowance permits entry into the applicable OPERATIONAL CONDITION CS) while relying on the ACTION requirement s. Operation with specific activity levels exceeding 0.2 microcurie per gram DOSE EQUIVALENT I-131 but less than or equal to 4 microcuries per gram DOSE EQUIVALENT I-131 must be restricted since these activity levels increase the 2-hour thyroid dose at the SITE BOUNDARY following a postulated steam line rupture.

Closing the main steam line isolation valves prevents the release of activity to the environs should a steam line rupture occur outside containment. The surveillanc e requirements provide adequate assurance that excessive specific activity levels in the reactor coolant will be detected in sufficient time to take corrective action.

3/4.4.6 PRESSURE/TEMPERATURE LIMITS All components in the reactor coolant system are designed to withstand the effects of cyclic loads due to system temperature and pressure changes. These cyclic loads are introduced by nor*mal load transients, reactor trips, and startup and shutdown operations. The various categories of load cycles used for design purposes are provided in Section 3.9 of the FSAR. During startup and shutdown, the rates of temperature and pressure changes are limited so that the maximum specified heatup and cooldown rates are consistent with the design assumptions and satisfy the stress limits for cyclic operation.

LIMERICK - UNIT 1 B 3/4 4-4 Amendment No . .iG., 4-G, 49-, J.s.9., 174

INTENTIONALLY LEFT BLANK REACTOR COOLANT SYSTEM

)

/

PRESSURE/TEMPERATURE LIMITS (Continued)

The operating limit curves of Figure 3.4.6.1-1 are derived from the fracture toughness requirements of 10 CFR 50 Appendix G and ASME Code Section XI, Appendix G. The curves are based on the RT 00, and stress intensity factor information for the reactor vessel components .. Fracture toughness limits and the basis for compliance *are more fully discussed in FSAR Ch~pter 5, Para-graph 5.3.1.5, "Fracture Toughness."

The reactor vessel materials have been tested to determine their initial RT00,. The results of these tests are shown in Table B 3/4.4.6-1. Reactor operation and resultant fast neutron, E greater than 1 MeV, irradiation will cause an increase in the RT 00,. Therefore, an adjusted reference temperature, based ~pon the fluence, nickel content and copper content of the material in question, can be predicted using Bases Figure B 3/4.4.6-1 and the recommenda-tions of Regulatory Guide 1.99, Revision 2, "Radiation Embrittlement of Reactor Vessel Materials." The pressure/temperature limit curves, Figure 3.4.6.1-1, include a shift in RTNor for conditions at 32 EFPY. The A, Band C limit curves are predicted to be bounding for all areas of the RPV until 32 EFPY. In addition, an intermediate A curve was previously provided for 22 EFPY. However, Unit 1 exceeded 22 EFPY during Cycle 14. Therefore, the A22 curve identified in Tech.

Spec. Figure 3.4.6.1-1 (Pressure/Temperature Curves) ~an no longer be used when performing the Reactor Vessel Pressure Test for Unit 1.

The pressure-temperature limit lines shown in Figures 3.4.6.1-1, curves C, and A, for reactor criticality and for inservice leak and hydrostatic testing have been provided to assure compliance with the minimum temperature requirements of Appendix G to 10 CFR Part SO for reactor criticality and for inservice leak and hydrostatic testing.

LIMERICK - UNIT 1 B 3/4 4-5 Amendment No. ~.~.-+/-49-,-+/-e-7-,

ECR 04-00575, Rev. 1

REACTOR COOLANT SYSTEM 3/4,4,Z MAIN STEAM LINE ISOLATION VALVES Double isolation valves are provided on each of the main steam lines to minimize the potential leakage paths from the containment 1n case of a line break.

Only one valve 1n each line is required to maintain the integrity of the containment, however, single failure considerations require that two valves be OPERABLE. The surveillance requirements are based on the operating history of this type valve. The maximum closure time has been selected to contain fission products and to ensure the core is not uncovered following line breaks. The minimum closure time 1s consistent with the assumptions 1n the safety analyses to prevent pressure surges.

3/4,4,8 CQELEIEDl 3/4,4,9 RESIDUAL HEAT REMOVAL The RHR system is required to remove decay heat and sensible heat in order to maintain the temperature of the reactor coolant. RHR shutdown cooling is comprised of four (4) subsystems which make two (2) loops. Each loop consists of two (2) motor driven pumps, a heat exchanger, and associated piping and valves. Both loops have a common suction from the same recirculation loop. Two (2) redundant, manually controlled shutdown cooling subsystems of the RHR System can provide the required decay heat removal capability, Each pump discharges the reactor coolant, after it has been cooled by circulation through the respective heat exchangers, to the reactor via the associated recirculation loop or to the reactor via the low pressure coolant injection pathway. The RHR heat exchangers transfer heat to the RHR Service Water System. The RHR shutdown cooling mode is manually controlled.

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

In HOT SHUTDOWN condition, the requirement to maintain OPERABLE two (2) independent RHR shutdown cooling subsystems means that each subsystem considered OPERABLE must be associated with a different heat exhanger loop, i.e., the HAH RHR heat exchanger with the "A" RHR pump or the "C" RHR pump, .anc1 the 11 B" RHR heat exchanger with the "B" RHR pump or the "D" RHR pump are two (2) independent RHR shutdown cooling subsystems. Only one Cl) of the two (2) RHR pumps associated w1th each RHR heat exchanger loop is LIMERICK - UNIT 1 B 3/4 4-6 Amendment No. 4-Q.,Q+,.i+Q.,~,-1-7+.

Associated with Amendment 199

REACTOR COOLANT SYSTEM BAE

-, 3/4.4.9 RESIDUAL HEAT REMOVAL (Continued) required to be OPERABLE for that independent subsystem to be OPERABLE. During COLD SHUTDOWN and REFUELING conditions, however, the subsystems not only have a common suction source, but are allowed to have a common heat exchanger and common discharge piping. To meet the LCO of two (2) OPERABLE subsystems, both pumps in one Cl) loop or*

one (1) pump in each of the two (2) loops must be OPERABLE. Since the piping and heai exchangers are passive components, that are assumed not to fail, they are allowed to be common to both subsystems. 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 Cl) 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.

Alternate decay heat removal methods are available to operators. These alternate methods of decay heat removal can be verified available either by calculation (which includes a review of component and system availability to verify that an alternate decay heat removal method is available) or by demonstration, and that a method of coolant mixing be operational. Decay heat removal capability by.amBient losses can be considered in evaluating alternate decay heat removal capability.

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 non-condensable gas into the reactor vessel. This surveillance verifies that the RHR Shutdown Cooling System piping is sufficiently filled with water prior to initially placing the system in operation during reactor shutdown. The RHR Shutdown Cooling System is OPERABLE when it is sufficiently filled with water to ensure that it can reliably perform its intended function.

The RHR Shutdown Cooling System is a manually initiated mode of the RHR System whose use is typically preceded by system piping flushes that disturb both the RHR pump suction and discharge piping. RHR Shutdown Cooling System is flushed and manually aligned for service using system operating procedures that ensure the RHR shutdown cooling suction and discharge flow paths are sufficiently filled with water. In the event that RHR Shutdown Cooling is required for emergency service, the system operating procedures that align and start the RHR System in shutdown cooling mode include the flexibility to eliminate piping flushes while maintaining minimum requirements to ensure that the suction and discharge flow paths are sufficiently filled with water. The RHR Shutdown Cooling System surveillance is met through the performance of the operating procedures that initially place the RHR shutdown cooling sub-system in service.

This surveillance requirement is modified by a Note allowing sufficient time (12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />) to align the RHR System for Shutdown Cooling operation after reactor dome pressure is less than the RHR cut-in permissive set point.

LIMERICK - UNIT 1 B 3/4 4-6a Amendment No. -+/--+/- Associated with Amendment 216

THIS PAGE INTENTIONALLY LEFT BLANK l(_

BASES TABLE 8 3L4.4. 6-1 REACTOR VESSEL TOUGHNESS*

HEAT/SLAB MIN.UPPER BELTLINE WELD SEAM I.D. OR STARTING SHELF COMPONENT OR MAT'L TYPE HEATLLOT cu 1%} Ni 1%} BTNor (OF} Lm.TNDr **{°F} {LFT-LBS} ART !1°F}

Plate SA-533 Gr. B,CL. 1 C 7677-1 .11 I

.5 +20 +35 NA 89 Weld AB (Field Weld) 640892 / .09 1. 0 -60 +58 NA J424B27AE 54 NOTES:

• Based on il0% of origin al rated power.

• • These values are given only for the benefi t of calcul ating the end-o f-life (EOL/32 EFPY) R'l'Nor NON-BELTLINE MT'L TYPE OR HEAT/SLAB OR HIGHEST STARTING COMPONENT WELD SEAM I.D. HEATLLOT R'l'NOr {°F}

Shell Ring SA 533, Gr. B, CL. 1 C7711-1 +20 Bottom Head Dome C7973- l +12 Bottom Head Torus C7973-1 +12 Top Head Dome A6834-1 +10 Top Head Torus 81993- 1 +10 Top Head Flange SA-508 , CL. 2 123Bl9 5-289 +10 Vessel Flange 2Vl924 -302 -20 Feedwa ter Nozzle Q2Q22W-412 -20 Weld Non-B eltline All -12 LPCI Nozzle *** SA-508 , CL. 2 Q2Q25W -6 Closur e Studs SA-540 , Gr. B-24 All Meet require ments of 45 ft-lbs and 25 mils Lat. Exp. at +10°F Note: *** The design of the LPCI nozzle s result s in their experi encing an EOL fluenc e in excess of 10 17 N/Cm2 which predic ts an EOL (32 EFPY) R'l'Nor of +41 °F.

LIMERICK - UNIT 1 B 3/4 4-7 Amendment fl,Jo. 3-6, ~ I I 145 SEP\ 15 am

-~

~

,~"

1.2 CX)

I 0 1.0

-X

>GJ l:

0.8 N -UJ E 0.6 u

C:

GJ u

C:

C>

. ([

a..

C:

0.4.

0

,4,J GJ z

0.2 0.0 10 Service L1fe (Years*)

BASES FIGURE B 3/4.4.6-1 FAST NEUTRON FLUENCE CE> 1 MeV) AT 1/4 T AS A FUNCTION OF SERVICE LIFE*

• At 90~ of Rated Thermal Power and 90" ava1lab111ty LIM~ICK - UNIT 1 B 3/4 4-8 Amendment No. 33,106 FEB 1 2 1996

3/4.5 EMERGENCY CORE COOLING SYSTEM BAE

) 3/4.5.1 and 3/4.5.2 ECCS - OPERATING and SHUIDOWN The core spray system (CSS), together with the LPCI mode of the RHR system, is provided to assure that the core is adequately cooled following a loss-of-coolant accident and provides adequate core cooling capacity for all break sizes up to and including the double-ended reactor recirculation line break, and for smaller breaks following depressurization by the ADS. Management of gas voids is important to ECCS injection/spray subsystem OPERABILITY.

The CSS is a primary source of emergency core cooling after the reactqr vessel is depressurized and a source for flooding of the core in case of accidental draining.

The surveillance requirements provide adequate assurance that the CSS will be OPERABLE when required. Although all active components are testable and full flow can be demonstrated by recirculation through a test loop during reactor operation, a complete functional test requires reactor shutdown.

The low pressure coolant injection (LPCI) mode of the RHR system is provided to assure that the core is adequately cooled following a loss-of-coolant accident. Four subsystems, each with one pump*, provide adequate core flooding for all break sizes up to and including the double-ended reactor recirculation line break, and for small breaks following depressurization by the ADS ..

The surveillance requirements provide adequate assurance that the LPCI system will be OPERABLE when required. Although all active components are testable and full flow can be demonstrated by recirculation through a test loop during reactor operation, a complete functional test requires reactor shutdown.

The high pressure coolant injection (HPCI) system is provided to assure that the reactor core.is adequately cooled to limit fuel clad temperature in the event of a small break in the reactor coolant system and loss of coolant which does not result in rapid depressurization of the reactor vessel. The HPCI system permits the reactor to be shut down while maintaining sufficient reactor vessel water level inventory until the vessel i~ depressurized. The HCPI system continues to operate until reactor vessel pressure is below the pressure at which CSS operation or LPCI mode of the RHR system operation maintains core cooling.

The capacity of the system is selected to provide the required core cooling.

The HPCI pump is designed to deliver greater than or equal .to 5600 gpm at reactor pressures between 1182 and 200 psig and is capable of delivering at least 5000 gpm between 1182 and 1205 psig. In the system's normal alignment, water from the condensate storage tank is used instead of injecting water from the suppression pool into the reactor, but no credit is taken in the safety analyses for the condensate storage tank water.

LIMERICK - UNIT 1 B 3/4 5-1 Amendment No. -l-0-e, +J.7.

ECR 00 00177, Associated with Amendment 216

EMERGENCY CORE COOLING SYSTEM ECCS - OPERATING and SHUTDOWN (Continued)

With the HPCI system inoperable, adequate core cooling is assured by the

~

OPERABILITY of the redundant and diversified automatic depressurization system and both the CS and LPCI systems. In addition, the reactor core isolation cooling (RCIC) system, a system for which no credit is taken in the safety analysis, will automatically provide makeup at reactor operating pressures on a reactor low water level condition. The HPCI out-of-service period of 14 days is based on the demonstrated OPERABILITY of redundant and diversified low pressure core cooling systems and the RCIC system. The HPCI system, and one LPCI subsystem, and/or one CSS subsystem out-of-service period of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> ensures that sufficient ECCS, comprised of a minimum of one CSS subsystem, three LPCI subsystems, and all of the ADS will be available to 1) provide for safe shutdown of the facility, and 2) mitigate and control accident conditions within the facility. A Note prohibits the application of Specification 3.0.4.b to an inoperable HPCI subsystem. There is an increased risk associated with entering an OPERATIONAL CONDITION or other specified condition in the Applicability with an inoperable HPCI subsystem and the provisions of Specification 3.0.4.b, which allow entry into an OPERATIONAL CONDITION or other specified condition in the Applicability with the Limiting Condition for Operation not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.

The surveillance requirements provide adequate assurance that the HPCI system will be OPERABLE when required. Although all active components are testable and full flow can be demonstrated by recirculation through a test loop during reactor operation, a complete functional test with reactor vessel injection requires reactor shutdown.

The ECCS injection/spray subsystem flow path piping and components have the er

'-_::i 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, isometMc 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 locations exceeds an acceptance criteria for gas volume at the suction or discharge of a pump), the Surveillance is not met. Accumulated gas should be eliminated or brought within the acceptance criteria limits. ECCS injection/spray

((;

LIMERICK - UNIT 1 B 3/4 5-2 Amendment No. B/10/94 -1:-t-P-,~.~.+W.

~ . Associated with Amendment 216

EMERGENCY CORE COOLING SYSTEM B E

.) ECCS - OPERATING and SHUTDOWN (Contin ued)

-- -~.--~

subsystem locatio ns suscep tible to gas accumulation are monitored and, if gas is found, the gas volume is compared to the acceptance criteri a for the locatio n. gas Suscep tible locatio ns in the same system flow path which are subject to the ofsame intrusi on mechanisms may be verifie d by monitoring a represe ntative subset suscep tible locatio ns. Monitoring may not be practic al for locatio ns that are inacces sible due to radiolo gical or environmental conditi ons, the plant configu ration, or personnel safety. For these locatio ns alterna tive methods (e.g.,

operati ng parameters, remote monitoring) .may be used to monitor the suscep tible locatio n. Monitoring is not required for suscept ible locatio ns where the maximum potenti al accumulated gas void volume has been evaluated and determined to not the challen ge system OPERABILITY. The accuracy of the method used for monitoring suscep tible locatio ns and trendin g of the results should be suffici ent to assure system OPERABILITY during the Surveil lance interva l.

Surveil lance 4.5.1.a .l.b is modified by a Note which exempts system vent flow paths opened under admini strative control . The admini strative control should be a dedicat ed individ ual at the system vent flow proced uralize d and include station ing This path who is in continuous communication with the operato rs in the control room.

close the system vent flow path if directe d.

individ ual will have a method to rapidly Upon failure of the HPCI system to function properl y after a small break loss-of -coolan t acciden t, the automa tic depress urizatio n system (ADS) automa-tically causes selecte d safety/ relief valves to open, depress urizing the reactor so that flow from the low pressur e core cooling systems can enter the core in time to limit fuel cladding temperature to less than 2200°F. ADS is conserv a-tively require d to be OPERABLE wheneve r reactor vessel pressur e exceeds 100 psig.

This pressur e is substa ntially below that for which the low pressur e core cool-ing systems can provide adequate core cooling for events requirin g ADS.

ADS automa tically contro ls five selecte d safety -relief valves. The for safety e~ The allowed out-of- service time one analys is assumes all five are operabl to other ECCS valve for up to fourtee n days is determi ned in a similar manner sub-sys tem out-of- service time allowan ces.

Verific ation that ADS accumulator gas supply header pressur e is ~90 psig ensures adequate gas pressur e for reliabl e ADS operati on. The accumu lator on each ADS valve provide s pneumatic pressur e for valve actuati on. The design pneumatic supply pressur e require ments for the accumu lator are such that, followi ng a tic supply to the accumu lator at least two valve actuati ons failure of the pneuma analys is can occur with the drywell at 70% of design pressur e. The ECCS d for operati on safety assumes only one actuati on to achieve the depress urizati* on require d

of the low pressur e ECCS. This minimum require d pressur e of ~90 psig is provide by the PCIG supply.

LIMERICK - UNIT 1 B 3/4 5-3 Amendment No. 8/10/94 -b-t-P-,-94,~,-+/--W.

&e-, Associ ated with Amendment 216

EMERGENCY CORE COOLING SYSTEM ECCS - OPERATING and SHUTDOWN (Continued) 3/4.5.3 SUPPRESSION CHAMBER The suppression chamber is required to be OPERABLE as part of the ECCS to ensure ,that a sufficient supply of water is available to the HPCI, CS and LPCI systems in the event of a LOCA. This limit on suppression chamber minimum water volume ensures that sufficient water is available to permit recirculation cooling flow to the core. The OPERABILITY of the suppression chamber in OPERATIONAL CONDITION 1, 2, or 3 is also required by Specification 3.6.2.1.

Repair work might require making the suppression chamber inoperable. This specification will permit those repairs to be made and at the same time give assurance that the irradiated fuel has an adequate cooling water supply when the suppression chamber must be made inoperable, including draining, in OPERATIONAL CONDITION 4 or 5.

In OPERATIONAL CONDITION 4 and 5 the suppression chamber minimum required water volume is reduced because the reactor coolant is maintained at or below 200°F. Since pressure suppression is not required below 212°F, the minimum water volume is based on NPSH, recirculation volume and vortex prevention plus a safety margin for conservatism.

~

\~-

LIMERICK - UNIT 1 B 3/4 5-4 Amendment No.~

Associated with Amendment 216

3/4.6 CONTAINMENT SYSTEMS

')

~~)~3/4.6.1 PRIMARY CONTAINMENT

-,~__....

3/4.6.1.1 PRIMARY CONTAINMENT INTEGRITY PRIMARY CONTAINMENT INTEGRiTY ensures that the release of radioactive mate-rials from the containment atmosphere will be restricted to those leakage paths and associated leak rates assumed in the safety analyses. This restriction, in conjunction with the leakage rate limitation, will limit the SITE BOUNDARY radiation doses to within the limits of 10 CFR Part 100 during accident conditions.

3/4.6.1.2 PRIMARY CONTAINMENT LEAKAGE The limitations on primary containment leakage rates ensure that the total containment leakage volume will not exceed the value calculated in the safety analyses at the design basis LOCA maximum peak containment pressure of 44 psig, Pa. As an added conservatism, the measured overall integrated leakage rate (Type A Test) is further limited to less than or equal to 0.75 La during performance of the periodic tests to account for possible degradation of the containment leakage barriers between leakage tests.

Operating experience with the main steam line isolation valves has indicated that degradation has occasionally occurred in the leak tightness of the valves; therefore the special requirement for testing these valves.

The surveillance testing for measuring leakage rates is consjstent with the Primary Containment Leak.age Rate Testing Program.

~ 3/4.6.1.3 PRIMARY CONTAINMENT AIR LOCK The limitations on closure and leak rate-for the primary containment air lock are required to meet the restrictions on PRIMARY CONTAINMENT INTEGRITY and the Primary Containment Leakage Rate Testing Program. Only one closed door in the air lock is required to maintain the integrity of the containment.

3/4.6.1.4 MSIV LEAKAGE ALTERNATE DRAIN PATHWAY*

Calculated doses resulting from the maximum leakage allowances for the main steamline isolation valves in the postulated LOCA situations will not exceed the criteria of 10 CFR. Part 100 guidelines, provided the main steam line system from the isolation valves up to and including the turbine condenser remains intact. Operating experience has indicated that degradation has occasionally occurred in the leak tightness of the MSIVs such that the specified leakage requirements have not always been continuously maintained. The requirement for the MSIV Leakage Alternate Drain Pathway serves to reduce the* offsite dose.

LIMERICK - UNIT *1 B 3/4 6-1 Amendment No.~. J..G.e., +G+, ~

ECR 11-00395

CONTAINMENT SYSTEMS 3/4.6.1,5 PRIMARY CONTAINMENT STRUCTURAL INTEGRITY er-This limita tion ensures that the struc tural integ rity of for the containment dards the life of will be maintained comparable to the origin al desig n'~tan the contai nment will the unit. Struc tural integ rity is required to ensure that of a LOCA. A visual withs tand the maximum calcu lated pressure in the event e Rate Testin g inspe ction in accordance with the Primary Containment Leakag Program is suffic ient to demonstrate this capab ility.

3/4.6.1.6 DRYWELL AND SUPPRESSION CHAMBER INTERNAL PRESSURE The limita tions on drywell and suppression chamber internthe al press ure ensure does not exceed design that the calcu lated containment peak pressure al press ure diffe r-the extern press ure of 55 psig during LOCA condi tions or that pressure diffe renti al of entia l does .not exceed the design maximum extern al The limit of - 1.0 to+ 2.0 psig for initia l contaithe nment pressure 5v0 psid. design will limit the total press ure to~ 44 psig which is less than press ure and is consi stent with the safety analy sis.

3/4.6.1.7 PRYWELL AVERAGE AIR TEMPERATURE The limita tion on drywell average air temperature ensuresrature that the con-design tempe of 340°F tainment peak air temperature does not exceed the with the safety analy sis.

during steam line break condi tions and is consi stent 1(**,,

.~ ~ .

3/4,6,l&B PRYWELL AND SUPPRESSION CHAMBER PURGE SYSTEM '*.,_*:;;c"' ---

The drywell and suppression chamber purge supply and exhaust isola tion valves are required to be closed during plant opera tion except as requir ed for inerti ng, deine rting, press ure contr ol, ALARA or air quali ty consi derat ions for personnel entry , or Surve illanc es that require the valve s to be open. Limiting

.the use of the drywell and suppression chamber purge system to speci fic crite ria

s. Analy sis indic ates is imposed to prote ct the integ rity of the SGTS filterutiliz ed, the assoc iated that should a LOCA occur while this pathway is being press ure surge through the (18 or 24") purge lines will adversely affec t the integ rity of SGTS. This condi tion is not impos ed on the 1 and 2 inch valves used for pressu re control since a surge throug h these lines does not threa ten the opera bility of SGTS.

Surve illanc e requirement 4.6.1 .8 ensures that the primar y. containment purge valves are closed as requir ed or, if open, open for valve an allowable reason. If a purge valve is open in viol*ation of this SR, the i~ conside~ed inope rable.

nment purge valves The SR is modified by a Note statin g that primary contai 1, 2 and 3. The SR are only required to be closed in OPERATIONAL CONDInot TIONS is also modif ied by a Note statin g that the SR is requir ed to be met when the purge valves are open for the stated reaso ns. The Note state s that these valves may be opened for inerti ng, deine rting, pressu re contr ol, ALARA or air quali ty consi derati ons for personnel entry , or Surve illanc es that requi re the valves to be open. The 18 or 24 inch purge valve s are capab le of closin g in There fore, these valve s are allowed to be the environment following a LOCA.

open for limite d periods of time. I

~~*~--

LIMERICK - UNIT 1 B 3/4 6-2 Amendment No. 6-9, ~.~ *.J,.l.g,-:1J.G, 186

CONTAINMENT SYSTEMS BAE 3/4.6.2 DEPRESSURIZATION SYSTEMS The specificatio ns of this section ensure that the primary ~ontainment pressure will not exceed the design pressure of 55 psig during primary system blowdown from full operating pressure. Management of gas voids is important to Suppression Pool Cooling/Spray Subsystem OPERABILITY.

The suppression chamber water provides the heat sink for the reactor coolant system energy release following a postulated rupture of the system. The suppression chamber water volume must absorb the associated decay and structural sensible heat released during reactor coolant system blowdown from rated conditions. Since all of the gases in the drywell are purged into the suppression chamber air space during a loss-of-cool ant accident, the pressure of the suppression chamber air space must not exceed 55 psig. The design volume of the suppression chamber, water and air, was obtained by considering that the total volume of reactor coolant is discharged to the suppression chamber and that the drywell volume is purged to the suppression chamber.

Using the minimum or maximum water volumes given in this specificatio n, suppression pool pressure during the design basis accident is below the design pressure. Maximum water volume of 134,600 ft 3 results in a downcomer submergence of 12'3" and the minimum volume of 122,120 ft 3 results in a submergence approximately 2'3" less. The majority of the Bodega tests were run with a submerged length of 4 feet and with complete condensation. Thus, with respect to the downcomer submergence, this specificatio n is adequate. The maximum temperature at the end of the blowdown tested during the Humboldt Bay and Bodega Bay tests was 170°F and this is conservative ly taken to be the limit for complete condensation of the reactor coolant, although condensation would occur for temperature above 170°F.

Should it be necessary to make the suppression chamber inoperable, this shall only be done as specified in Spec\ficatio n 3.5.3.

Under full power operating conditions, blowdown through safety/relie f valves assuming an initial suppression chamber water temperature of 95°F results in a bulk water temperatur~ of approximately 140°F immediately following blowdown which is below the 190°F bulk temperature limit used for complete condensation via T-quencher devices. At this temperature and atmospheric pressure, the available NPSH exceeds that required by both the RHR and core spray pumps, thus there is no dependency on containment overpressure during the accident injection phase. If both RHR loops are used for containment cooling, there is no dependency on containment overpressure for post-LOCA operations.

• LIMERICK - UNIT 1 B 3/4 6-3 Amendment No. JJ, B-7, -&, -+/--G-e-,

Associated with Amendment 216

CONTAINMENT SYSTEMS 3/4.6.2 DEPRESSURIZATION SYSTEMS (Continued)

RHR Suppression Pool Cooling/Spray subsystem p1p1ng 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 subsystems and may also prevent water hammer and pump cavitation.

Selection of RHR Suppression Pool Cooling/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 RHR Suppression Pool Cooling/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 locations exceeds an acceptance criteria for gas volume at the suction or discharge of a pump), the Surveillance is not met.

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

RHR Suppression Pool Cooling/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 same system flow path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representative subset of susceptible locations. Monitoring may not be practical for locations that are inaccessible due to ra9iological 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.

One of the surveillance requirements for the suppression pool cooling (SPC) mode of the RHR system is to demonstrate that each RHR pump develops a flow rate 3

10,000 gpm while operating in the SPC mode with flow through the heat exchanger and its associated closed bypass valve, ensuring that pump performance has not degraded during the cycle and that the flow path is.operable. This test confirms one point on the pump design curve and is indicative of overall performance. Such inservice inspections confirm component operability, trend performance and detect incipient failures by indicating abnormal performance. The RHR heat exchanger bypass valve is used for adjusting flow through the heat exchanger, and is not designed to be a tight shut-off valve. With the bypass valve closed, a portion of the total flow still travels through the bypass, which LIMERICK - UNIT 1 B 3/4 6-3a Amendment No. -s-7-, ,eg Associated with Amendment 216

CONTAINMENT SYSTEMS B E

~)3/4. 6.2 DEPRESSURIZATION SYSTEMS (Continued)

/

can affect overal l heat transf er. However, no heat transf er performcal ance requirement of the heat exchanger is intende d by the curren t Techni of any flow Specif ication survei llance requirement. This is confirmed by the lack3/4.7. 1.

requirement for the RHRSW system in Technical Specif ication s Section strate heat Verify ing an RHR flowra te through the heat exchanger does not demon LGS does removal capab ility in the absence of a requirement for RHRSW flow.

perform heat transf er testin g of the RHR heat exchangers as part of require its response d the commit ment to meet the ments of to Generic Letter 89-13, which verifie GDC 46.

be Experimental data indica te that excess ive steam condensing loads can below suppre ssion pool is mainta ined avoided if the peak local temper ature of the s.

200°F during any period of relief valve operat ion for T-quencher device condit ions so Specif ication s have been placed on the envelope of reacto r operat ing manner to avoid the regime of that the reacto r can be depres surize d in a timely poten tially high suppre ssion chamber loadin gs.

Because of the large volume and thermal capaci ty of the suppression pool, these the volume and temper ature normally changes very slowly and monitoringBy requir ing parameters daily is suffic ient to establ ish any temperature trends .

s of the suppre ssion pool tempe rature to be freque ntly recorded during period d so signif icant heat additi on, the temperature trends will be closel y followe that approp riate action can be taken.

) In additio n to the limits on temperature of the suppression chambersafety pool in the event a -

water; operat ing* procedures define the action to be taken action shall relief valve inadve rtently opens *or sticks open. As a minimum this te suppres-includ e: (1) use of all availa ble means to close the valve, (2) initia other safety -

sion pool water. coolin g, (3) initia te reacto r shutdow n, and (4) if discha rge shall be relief valves are used to depres surize the reacto r, their mixing and separa ted from that of the stuck-open safety /relief valve to assure unifor mity of energy insert ion to the pool.

chamber During a LOCA, potent ial leak paths between the drywell and suppression the steam flow into airspa ce could result in excess ive containment pressu res, since ial sources

r. Potent the airspa ce would bypass the heat sink capab ilities of the chambe rs (VBs),

of bypass leakage are the suppression chamber-to-drywell vacuum breake liner plate and penetrations in the diaphragm floor, and cracks in the diaphragm floor and/or pressu re downcomers located in the suppression chamber airspa ce. The containmentactuat ing the response to the postul ated bypass leakage can be mitiga ted by manually leakage area of suppression chamber spr*ays. An *analysis was performed for a design bypassto initia te the A/~k equal to 0.0500 ft 2 to verify that the operator has suffic ient time limit of 10% of The sprays prior to exceeding the containment design pressure of 55 psig. bypass analys is the design value of 0.0500 ft ensures 2

that the design basis for the steam is met.

LIMERICK - UNIT 1 B 3/4 6-3b Amendment No. Ia+,~

Associated with Amendment 216

THIS PAGE INTENTIONALLY LEFT BLANK

• c

~--*

CONTAINMENT SYSTEMS BASES

) DEPRESSURIZATION SYSTEMS (Continued)

---

n1"e drywe I 1-to-suppressioncnamber bypass test at a differential pressure of at least 4.0 psi verifies the overall bypass leakage area for simulated LOCA condi~ions is less than the specified limit. For those outages where the drywell-to-suppression chamber bypass leakage test in not conducted, the VB leakage test verifies that the VB leakage area is less than the bypass limit, with a 76% margin to the bypass limit to accommodate the remaining potential leakage area through the passive structural components. Previous drywell-to-suppression chamber bypass test data indicates that the bypass leakage through the passive structural components will be much *less than the 76% margin. The VB leakage limit, combined with the negligible passive structural leakage area, ensures that the drywell-to-suppression chamber bypass leakage limit is met for those outages for which the drywell-to-suppression chamber bypass test is not scheduled.

3/4.6.3 PRIMARY CONTAINMENT ISOLATION VALVES The OPERABILITY of the primary containment is-elation valves ensures that the containment atmosphere will be isolated from the outside environment in the event of a release of radioactive material to the containment atmosphere or pressurization of the containment and is consistent with the requirements of GDC 54 through 57 of Appendix A of 10 CFR Part 50. Containment isolation within the time limits specified for those isolation valves designed to close automatically ensures that the release of radioactive material to the environ-ment will be consistent with the assumptions used in the analyses for a LOCA.

The scram discharge volume vent and drain valves serve a dual function, one of which is primary containment isolation. Since the other safety functions of the scram discharge volume vent and drain valves would not be available if the normal PCIV actions were taken, actions are provided to direct the user to the scram discharge volume vent and drain operability requirements contained in Specification 3.1.3.1.

However, since the scram discharge volume vent and drain valves are PCIVs, the Surveillance Requirements of Specification 4.6.3 still apply to these valves.

The opening of a containment isolation valve that was locked or sealed closed to satisfy Technical Specification 3.6.3 Action statements, may be reopened on an intermittent basis under administrative controls. These controls consist of stationing a dedicated individual at the controls of the valve, who is in continuous communication with the control room. In this way, the penetration can be rapidly isolated when a need for primary containment isolation is indicated.

Primary containment isolation valves governed by this -Technical Specification are identified in Table 3.6.3-1 of the TRM.

This Surveillance Requirement requires a demonstration that a representative sample of reactor instrument line excess flow check valves (EFCVs) is OPERABLE by verifying that the valve actuates to the isolation position on a simulated instrument line break signal. The representative sample consists of an approximately equal number of EFCVs, such that each EFCV is tested in accordance with the Surveillance Frequency Control Program. In addition, the EFCVs in the sample are representative of the various plant configurations, models, sizes, and operating environments. This ensures that any potentially common problem with a specific type or application of EFCV is detected at the earliest possible time. This Surveillance Requirement provides assurance that the instrumentation line EFCVs will perform so that predicted radiological consequences will not be exceeded during a postulated instrument line break event. Furthermore, any.

EFCV failures will be evaluated to determine if additional testing in the test interval is warranted to ensure overall reliability is maintained. Operating experience has demonstrated that these components are highly reliable and that failures to isolate ar~----*-

. ~---- very infrequent. Therefore ;-test, ng o-f a representat, ve samp I e was concluaed to be

, acceptable from a reliability standpoint. For some EFCVs, this Surveillance can be

~ performed with the reactor at power.

LIMERICK - UNIT 1 B 3/4 6-4 Amendment No. 48,~,W,MfJ,J.@,186

CONTAINMENT SYSTEMS BASES 3/4.6.4 VACUUM RELIEF Vacuum relief valves are provided to equalize the pressure between the suppressi on chamber and drywell. This system will maintain the structura l integrity of the primary containme nt under condition s of large different ial pressures .

The vacuum breakers between the suppressio n chamber and the drywell must not be inoperabl e in the open position since this would allow bypassing of the suppressi on pool in case of an accident. Two pairs of valves are required to protect containme nt structura l integrity . There are four pairs of valves (three to provide minimum redundancy ) so that operation may continue for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> with no more than two pairs of vacuum breakers inoperabl e in the closed position.

Each vacuum breaker valve's position indication system is of great enough sensitivi ty to ensure that the maximwn steam bypass leakage coefficie nt of A

..Jk = 0 .05 ft2 for the vacuum relief system (assuming one valve fully open) will not be exceeded.

LIMERICK - UNIT 1 B 3/4 6-4a Amendment No. 148 I

CONTAINMENT SYSTEMS BASES 3/4 .* 6. 5 SECONDARY CONTAIN!~ENT

• =!

• • • ...*, /I Secondary conttJinment is designed to minimize any ground level release of radioactive* material which may result from an accident. The Reactor Enclosure

• and associated structures provide secondary containment during normal operation when the* drywell is sealed and in s*ervice. At other times the drywell may be open and. when required, second'ary containment integrity is specified.

Establfshing and maintaining a vacuum in the reactor enclosure secondary containment with the standby gas treatment system in accordance with the Surveillance Frequency Control Program, along with the survetllance of the doors, hatchesj da~pers and valves, is adequate to ensure that there are no violations of the integrity of the secondary containment.

The OPERABILITY of the reactor enclosure recirculatio n system and the standby gas treatment systems ensures that sufficient iodine removal capability will be- available tn. the event of a LOCA. The reduction in containment iodine inventory reduces the r.esul ti rig SHE BOUNDARY arid Cont ro 1 Room radiation doses associated with containment leakage. The operation of these systems and resultant iodine removal capacity are consistent with the assumptions ~sed in the LOCA analysis. Provisions have bE;!en made to continuously purge the filter plenums with ihstrument air*when the filt~rs are not in use to prevent buildup of moisture on the adsorbers and the HEPA filters.

As a result of the Alternative Source Term (AST) project, secondary containment ihtegritY of the refueling area is not required during certain conditions when handling_ irradiated fuel or during CORE ALTERATIONS and a1i'gnmerit of the Sta.ndby Gas Treatment System to the refueling area is not required. The control roqm dose an~lys1s fa~ the Fuel Handling Accident (FHA) ts based on unfiltered re1eases from the South Stack and therefore, does not require the Standby 6ai Treatment System-to be aligned to the refueling area.

However, when handling RECENTLY IRRADIATED FUEL or during operations with a potential for draining the reactor vesse.1 with the vessel head removed and fuel in the vessel, secondary containment integrity of the refueling area is required and alignment of the Standby Gas Treatment System to the refueling area is required.

The AST fuel handlfog analysis does not include an accident involving RECENTLY IRRADIATED FUEL or an accident involving draining the reactor vessel.

The Standby Gas Treatment System is required to be OPERABLE when handling irradiated fuel, handling Rl:-CENTLY IRRADIATED FUEL, during CORE ALTERATIONS and during op~rations with a potential to drain the vessel with the vessel head removed and fuel i ri the vessel. Fuel Handling Accident rel eases from _the North Stack must be filtered through the Standby Gas Treatment System to maintain control room doses ~ithin regulatory limits. The OPERABILITY of the Standby Gas T~eatment System assutes that teleases, if made through the North Stackj are filtered prior to release.*

LIMERICK - UNIT 1 B 3/4 6-5 Amendment No. -s,40,A.~.m.

~ . ~ , ECR LG 09-00052

CONTAINMENT SYSTEMS SECONDARY CONTAINMENT (Continued)

Surveillances 4.6.5.1.1.a and 4.6.5.1.2.a are each modified by a footnote (*)

which states the surveillance is not required to be met for up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> if an analysis demonstrates that one standby gas treatment subsystem remains capable of establishing the required secondary containment vacuum. Use of the footnote is expected to be infrequent but may be necessitated by situations in which secondary containment vacuum may be less than the required containment vacuum, such as, but not limited to, wind gusts or failure or change of operating normal ventilation subsystems. These conditions do not indicate any change in the leak tightness of the secondary containment boundary. The analysis should consider the actual conditions (equipment configuration, temperature, atmospheric pressure, wind conditions, measured secondary containment vacuum, etc.) to determine whether, if an accident requiring secondary containment to be OPERABLE were to occur, one train of standby gas treatment could establish the assumed secondary containment vacuum within the time assumed in the accident analysis. If so, the surveillance may be considered met for a period up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The 4-hour limit is based on the expected short duration of the situations when the footnote would be applied.

Surveillances 4.6.5.1.1.b.2 and 4.6.5.1.2.b.2 require verifying that one secondary containment personnel access door in each access opening is closed which provides adequate assurance that exfiltration from the secondary containment will not occur. An access opening contains at least one inner and one outer door. The intent is to not breach the secondary containment, which is achieved by maintaining the inner or outer personnel access door closed.

Surveillances 4.6.5.1.1.b.2 and 4.6.5.1.2.b.2 provide an allowance for brief, inadvertent, simultaneous openings of redundant secondary containment personnel C

access doors for normal entry and exit conditions.

• Although the safety analyses assumes that the reactor enclosure secondary containment draw down time will take 930 seconds, these surveillance require-ments specify a draw down time of 916 seconds. This 14 second difference is due to the diesel generator starting and sequence loading delays which is not part of this surveillance requirement.

The reactor enclosure secondary containment draw down time analyses assumes a starting point of 0.25 inch of vacuum water gauge and worst case SGTS dirty filter flow rate of 2800 cfm. The surveillance requirements satisfy this as-sumption by starting the drawdown from ambient conditions and connecting the adjacent reactor enclosure and refueltng area to the SGTS to split the exhaust flow between the three zones and verifying a minimum flow rate of 2800 cfm from the test zone. This simulates the worst case flow alignment and verifies ade-quate flow is available to drawdown the test zone within the required time.

The Technical Specification Surveillance Requirement 4.6.5.3.b.3 is intended to be a multi-zone air balance verification without isolating any test zone.

LIMERICK - UNIT 1 B 3/4 6-5a Amendment No. ~.4-G,-7-+/--,~.~.

S&,~. ECR LG 09 00052, Associated with Amendment~. 229

CONTAINMENT SYSTEMS B E

)

SECONDARY CONTAINMENT (Continued)

The SGTS fans are sized for three zones and therefore, when aligned to a single zone or two zones, will have excess capacity to more quickly drawdown the affected zones. There is no maximum flow limit to individual zones or pairs of zones and the air balance and drawdown time are verified when all three zones are connected to the SGTS.

The three zone air balance veri.fication and drawdown test will be done after any major system alteration, which is any modification which will have an effect on the SGTS flowrate such that the ability of the SGTS to drawdown the reactor enclosure to greater than *or equal to 0.25 inch of vacuum water gage in less than or equal to 916 seconds could be affected.

LIMERICK - UNIT 1 B 3/4 6-Sb Amendment No. ~.4-G-,++/--, ~.~.

~ . ~ . ECR LG 09 00052, Associated with Amendment 2-G-, 229

C THIS PAGE INTENTIONALLY LEFT BLANK L

CONTAINMENT SYSTEMS I

3/4.6.5 SECONDARY CONTAINMENT (Continued) I The field tests for bypass leakage across the SGTS charcoal adsorber and HEPA filter banks are performed at a flow rate of 5764 +/- 10% cfm. The laboratory analysis performed on the SGTS carbon samples will be tested at a velocity of 66 fpm based on the system residence time.

The SGTS filter train pressure drop is a function of air flow rate and filter conditions. Surveillance testing is performed using either the SGTS or drywell purge fans to provide operating convenience.

Each reactor enclosure secondary containment zone and refueling area secondary containment zone is tested independently to verify the design leak tightness. A design leak tightness of 2500 cfm or less for each reactor enclosure and 764 cfm or less for*the refueling area at a 0.25 inch of vacuum water gage will ensure that containment integrity is maintained at an acceptable level if all zones are connected to the SGTS at the same time.

The Reactor Enclosure Sicondary Containment Automatic Isolation Valves and Refueling Area Secondary Containment Automatic Isolation Valves can be found in the UFSAR.

The post-LOCA offsite dose analysis assumes a reactor enclosure secondary containment post-draw down leakage rate of 2~00 cfm and certain post-accident X/Q values. While the post-accident X/Q values represent a statistical inter-pretation of historical meteorological data, the highest ground level wind speed which can be associated_wi.th these values is 7 mph (Pasquill-Gifford stability Class G for a ground level release). Therefore, the surveillance requirement assures that the reactor enclosure secondary containment is verified under meteorological conditions consistent-with the assumptions utilized in the design basis analysis. Reactor Enclosure Secondary Containment leakage tests that are successfully performed at wind speeds in excess of 7 mph would also satisfy the leak rate surveillance requirements, since it shows compliance with more conservative test conditions.

3/4.6.6 PRIMARY CONTAINMENT ATMOSPHERE CONTROL The primary containment atmospheric mixing system is provided to ensure adequate mixing of the containment atmosphere to prevent localized accumulations of hydrogen and oxygen from exceeding the lower flammability limit during post-LOCA conditions.

All nuclear reactors must be designed to withstand events that generate hydrogen either due to the zirconium metal water reaction in the core or due to radiolysis. ,The primary method to control hydrogen is to inert the primary containment. With the primary containment inert, that is, oxygen concentration

<4.0 volume percent Cv/o), a combustible mixture cannot be present in the primary containment for any hydrogen concentration. The capability to inert the primary containment and maintain oxygen <4.0 v/o works together with Drywell Hydrogen Mixing System to provide redundant and diverse methods to mitigate events that produce hydrogen.

LIMERICK - UNIT 1 B 3/4 6-6 Amendment No. i, +Oa, ~.

ECR QQ QQ1J2, 173

THIS PAGE INTENTIONALLY LEFT BLANK 3901038720 3/4. 7 PLANT SYSTEMS

) BASES . ~.*. - ...

1/4. 7.1 SERVICE WATER SYSTEMS* COMMON SYSTEMS The OPERABILITY of tht service water systems ensures that sufficient cooling \

capacity is available for continued operation of saf1ty*relat1d equipmant during normal and *accident conditions. The redundant cooling capacity of these systems,

• assuming a single failure, is consistent with the assumptions used in the accident conditions within acceptable limits.

The RHR and ESW systems ar, common to Units 1 and 2 and consist af two independent subsystems each with two pumps. One p~ per subsystem (loop) is powered. from a Unit 1 safeguard bus and the other pump is powered from a Unit 2 safeguard bus. In order to ensure adequate onsite power sources to the systems during a loss of offsite power event, the inoperability of th1s1 supplies are restricted fn system ACTION statements.

RHRSW is a manually operated system used for core and containment heat removal. Each of two RHRSW subsystems has one heat exchanger p1r unit. Each RHRSW pump provides adequate cooling for one RHR h11t exchanger. By limit;ng operation with less* than three OPERABLE RHRSW pumps with OPERABLE Di1s1l Gen1rators, ea.ch unit is ensured adequate heat removal capability fo.r the tllJ design scenario of LOCA/LOOP on on1 unit and simultaneous safe shutdown of the other unit.

Each* ESW pump provides adequate flow to the cooling loads ;nits associated loop. *with only two divisions of power required for LDCA mitigation of one unit and one div;sion of power required for safe shutdown of the other unit, one ESW pump provid1s suffici1nt_cap1city to fulfill design requiremeats. ESW pumps 1r1 automatically started upon start of the associated Dies1l Generators. Therefor,, the allowable out of service times for OPERABLE ESW pumps and their associated Diesel Generators is liaited to ensure*adequat1 cooling during a loss of offsite power event.

LIMERICK* UNIT 1 a 3/4 ,-1 Am1AfJm1ni*Ha*. 27 .l Jll 11 ~

PLANT SYSTEMS 3/4.7.2 CONTROL ROOM EMERGENCY FRESH AIR SUPPLY SYSTEM - COMMON SYSTEM The OPERABILITY of the control room emergency fresh air supply system ensures that the control room will remain habitable for occupants during and following an uncontrolled release of radioactivity, hazardous chemicals, or smoke. Constant purge of the system at 1 cfm is sufficient to reduce the buildup of moisture on the adsorbers and HEPA filters. The OPERABILITY of this system in conjunction with control room design provisions is based on limiting the radiation exposure to personnel occupying the control room to 5 rem or less Total Effective Dose Equivalent. This limitation is consistent with the requirements of 10 CFR Part 50.67, Accident Source Term.

Since the Control Room Emergency Fresh Air Supply System is not credited for filtration in OPERATIONAL CONDITIONS 4 and 5, applicability to 4 and 5 is only required to support the Chlorine and Toxic Gas design basis isolation requirements.

The Control Room Envelope (CRE) is the area within the confines of the CRE boundary that contains the spaces that control room occupants inhabit to control the unit during normal and accident conditions. This area encompasses the control room, and other ~oncritical areas including adjacent support offices~ toilet and utility rooms. The CRE is protected during normal operation, natural events, and accident conditions. The CRE boundary is the combination of walls, floor, ceiling, ducting, valves, doors, penetrations and equipment that physically form the CRE. The OPERABILITY of the CRE boundary must be maintained to ensure that the inleakage of unfiltered air into the CRE will not exceed the inleakage assumed in the licensing basis analysis of design basis accident (OBA) consequences to CRE occupants. The CRE.and its boundary are defined in the Control Room Envelope Habitability Program.

In addition, The CREFAS System provides protection from smoke and hazardous chemicals to the CRE occupants. The analysis of hazardous chemical releases demonstrates that the toxicity limits are not exceeded in the CRE following a hazardous chemical release (Ref. 1). The evaluation of a smoke challenge demonstrates that it will not result in the inability of the CRE occupants to control the reactor either from the control room or from the remote shutdown panels (Ref. 2).

In order for the CREFAS subsystems to be considered OPERABLE, the CRE boundary must be maintained such that the CRE occupant dose from a large radioactive release does not exce~d the calculated dose in the licensing basis consequence analyses for DBAs, and that CRE occupants are protected from hazardous chemicals and smoke.

The LCO is modified by a Note allowing the CRE boundary to be opened intermittently under administrative controls. This Note only applies to openings in the CRE boundary that can be rapidly restored to the design condition, such as doors, hatches, floor plugs, and access panels. For entry and exit through doors, the administrative control of the opening is performed by the person(s) entering or exiting the area. For other openings, these controls should be prDceduralized and consist of stationing a dedicated individual at the opening who is in continuous communication with the operators in the CRE. This individual will have a method to rapidly close the opening and to restore the CRE boundary to a condition equivalent to the design condition when a need for CRE isolation is indicated.

LIMERICK - UNIT 1 B 3/4 7-la Amendment No. ~.4G.~ +8&, 188 1

PLANT SYSTEMS If the unfiltered inleakage of potentially contaminated air past the CRE boundary and into the CRE can result in CRE occupant radiological dose greater than the calculated dose of the licensing basis analyses of OBA consequences (allowed to be up to 5 ~em TEDE), or inadequate protection of CRE occupants from hazardous chemicals or smoke, the CRE boundary is inoperable. Actions must be taken to restore an OPERABLE CRE boundary within 90 days.

During the period that the CRE boundary is considered inoperable, action must be initiated immediately to implement mitigating actions to lessen the effect on CRE occupants from the potential hazards of a radiological or chemical event or a challenge from smoke. Actions must be taken within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to verify that in the event of a OBA~ the mitigating actions will ensure that CRE occupant radiological exposures will not exceed the calculated dose of the licensing basis analyses of OBA consequences, and that CRE occupants are protected from hazardous chemicals and smoke. These mitigating actions (i.e., actions that are taken to offset the consequences of the inoperable CRE boundary) should be preplanned for implementation upon entry into the condition, regardless of whether entry is intentional or unintentional. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Time is reasonable b~sed on tbJ= low probability of a OBA occurring during this time period, and the use of mitigating actions. The 90 day Completion Ti~e is reasonable based on the determination that the mitigating actions will ensure protection of CRE occupants within analyzed limits while limiting the probability that CRE occupants will have to implement protective measures that may adversely affect their ability to

.*~ control the reactor and maintain it in a safe shutdown condition in the event of a OBA. In addition, the 90 day Completion Time is a reasonable time to diagnose, plan and possibly repair, and test most problems with the CRE boundary.

SR 4.7.2.2 verifies the OPERABILITY of the CRE boundary by testing for unfiltered air inleakage past the CRE boundary and into the CRE. The details of the testing are specified in the Control Room Envelope Habitability Program.

The CRE is considered habitable when the radiological dose to CRE occupants calculated in the licensing basis analyses of OBA consequences is no more than 5 rem Total Effective Dose Equivalent and the CRE occupants are protected from hazardous chemicals and smoke. SR 4.7.2.2 verifies that the unfiltered air inleakage into the CRE is no greater than the flow rate assumed in the licensing basis analyses of OBA consequences. When unfiltered air inleakage is greater than the assumed flow rate, Required Action 3.7.2.a.2 must be entered. Required Action 3.7.2.a.2.c allows time to restore the CRE boundary to OPERABLE status provided mitigating actions can ensure.that the CRE remains within the licensing basis habitability limits for the occupants following an accident. Compensatory measures are discussed in Regulatory Guide 1.196, Section C.2.7.3, (Ref. 3) which endorses, with exceptions, NEI 99-03, Section 8.4 and Appendix F (Ref. 4). These compensatory measures may also be used as mitigating actions as required by Required Action 3.7.2.a.2.b. Temporary analytical methods may also be used as compensatory measures to restore OPERABILITY (Ref. 5). Options for restoring the CRE boundary to OPERABLE status include changing the licensing basis OBA consequence analysis, repairing the CRE boundary, or a combination of these actions. Depending upon the nature of the problem and the corrective action, a full scope inleakage test may not be necessary to establish that the CRE boundary has been restored to OPERABLE status.

LIMERICK - UNIT 1 B 3/4 7-lb Amendment No. i+,40,J.&9.~. 188

PLANT SYSTEMS 3/4.7.2 CONTROL ROOM EMERGENCY FRESH AIR SUPPLY SYSTEM - COMMON SYSTEM (Continued) ~

REFERENCES

1. UFSAR Section 6.4

2. UFSAR Section 9.5

3. Regulatory Guide 1.196

4. NEI 99-03, "Control Room Habitability Assessment Guidance, "June 2001.

5. Letter from Eric J. Leeds CNRC) to James W. Davis CNEI) dated January 30, 2004, "NEI Draft White Paper, Use of Generic Letter 91-18 Process and Alternative Source Terms in the Context of Control Room Habitability." (ADAMS Accession No. ML040300694).

3/4.7.3 REACTOR CORE ISOLATION COOLING SYSTEM The reactor core isolation cooling CRCIC) system is provided to assure adequate core cooling in the event of reactor isolation from its primary heat sink and the loss of feedwater flow to the reactor vessel without requiring actuation of any of the emergency core cooling system equipment. The RCIC system is conservatively required to be OPERABLE whenever reactor pressure ex-ceeds 150 psig. This pressure is substantially below that for which low pressure core cooling systems can provide adequate core cooling. Management of gas voids is important to RCIC System OPERABILITY.

The RCIC system specifications are applicable during OPERATIONAL CONDITIONS 1, 2, and 3 when reactor vessel pressure exceeds 150 psig because RCIC is the primary non-ECCS source of emergency core cooling when the reactor is pressurized.

With the RCIC system inoperable, adequate core cooling is assured by the OPERABILITY of the HPCI system and justifies the specified 14 day out-of-service period. A Note prohibits the application of Specification 3.0.4.b to an inoperable RCIC system. There is an increased risk associated with entering an OPERATIONAL CONDITION or other specified condition in the Applicability with an inoperable RCIC subsystem and the provisions of Specification 3.0.4.b, which allow entry into an OPERATIONAL CONDITION or other specified condition in the Applicability with the Limiting Condition for Operation not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.

The surveillance requirements provide adequate assurance that RCIC will be OPERABLE when required. Although all active components are testable and full flow can be demonstrated by recirculation during reactor operation, a complete functional test requires reactor shutdown.

LIMERICK - UNIT 1 B 3/4 7-lc Amendment No. l-7-,4-G,-l-&-9,+g.f.,J..gg, Associated with Amendment 216

PLANT SYSTEMS BAE 3/4.7.3 REACTOR CORE ISOLATION COOLING SYSTEM (Continued)

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 required RCIC System and may also prevent water hammer, pump cavitation, and pumping of noncondensible gas into the reactor vessel.

Selection of RCIC 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 RCIC ~ystem 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 locations exceeds an acceptance criteria for gas volume at the* suction or discharge of a pump), the Surveillance is not 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 fo~ 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 subset 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.

Surveillance 4.7.3.a.2 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.

LIMERICK - UNIT 1 B 3/4 7-ld Associated with Amendment 216 I

PLANT SYSTEMS BASE The "Snubber Program" manages the requirement for demonstrating snubber operability (examination, testing and.service life monitoring) as reflected in TS Section 6.8.4.k thereby ensuring the TS remains consistent with the ISI program. The program for in service testing of snubbers in accordance with ASME OM Code and the applicable addenda as required by 10 CFR 50.SSa(g) is required* to include evaluation of supported components/systems when snubbers are found to be inoperable.

LIMERICK - UNIT 1 B 3/4 7-2 Amendment No. -21,*40, l, 2231

• PLANT SYSTEMS SNUBBERS (Continued) 3/4.7.5 SEALED SOURCE CONTAMINATION The limitations on removable contamination for sources requ1r1ng leak testing, including alpha emitters, is based on 10 CFR 70.39(c) limits for plutonium. This limitation will ensure that leakage from byproduct, source, and special nuclear material sources will not exceed allowable intake values. Sealed sources are classified into three groups according to their use*, with surveillance requirements commensurate with the probability of damage to a source in that group. Those sources which are frequently handled are required to be tested more often than those which are not. Sealed sources which are continuously enclosed within a shielded mechanism, i.e,, sealed sources within radiation monitoring devices, are considered to be stored and need not be tested unless they are removed from the shielded mechanism.

LIMERICK - UNIT 1 B 3/4 7-3 Amendment No. 4, '8%, 223

., PLANT SYSTEMS BASES 3/4 7.6 (Deleted) - INFORMATION FROM THIS SECTION RELOCATED TO THE TRM.

3/4.7.7 (Deleted) - INFORMATION FROM THIS SECTION RELOCATED TO THE TRM.

DEC 2 0 11S LIMERICK - UNIT I B 3/4 7-4 Amendment No. 104

PLANT SYSTEMS BASES 3/4 7.8 MAIN TURBINE BYPASS SYSTEM The required OPERABILITY of. the main turbine bypass system is consistent with the assumptions of the feedwater controller failure analysis in the cycle specific transient analysis.

The main turbine bypass system is required to be OPERABLE to limit peak pressure in the main steam lines and*to maintain reactor pressure within acceptable limits during events that cause rapid pressurization such that the Safety Limit MCPR is not exceeded. With the main turbine bypass system inoperable, continued operation is based on the cycle specific transient analysis which has been performed for the feedwater controller failure, maximum demand with bypass failure.

LIMERICK - UNIT 1 B 3/4 7-5 Amendment No. 52 OCT 2 4 1991

3/4.8 ELECTRICAL POWER SYSTEMS

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J .;;;... ,.-== ===- -_...,- ==== -=== =:im ::::a: i:m:a ::=---

nd-4)NSltL.POW ER

--3z:4:a::::r.-=314:;:a-;z-:---:a:cHf4-;--8:;:3+/-fu:::-SGl:!R-G---S-dhfu----SQURCT--S-.-d DISTRIBUTION SYSTEMS iated distr ibuti on The OPERABILITY of the.A.C. and D.C. power sources* andbeassoc avail able to supply systems during opera tion ensures that suffi cient power will shutdown of the facil ity and the safet y-rel ated equipment required for Cl) the safe withi n the facil ity. The (2) the mitig ation and control of accident conditions power sources and minimum speci fied independent and redundant A.C. and D.C. Design Crite rion 17 of distr ibuti on systems satis fy the requirements of General Appendix A to 10 CFR Part 50.

ers, switches, An offsi te power source consi sts of all break ers, transformpower from the requi red to trans mit inter rupti ng devic es, cabli ng, and contr ols ency bus or buses. The offsi te trans missi on network to the onsit e Class lE emerg of power is dependent upon grid e

determination of the OPERABILITY of an offsi te sourc the design basis calcu lation and plant facto rs that, when taken toget her, describe of these facto rs ensures that requirements for voltage regul ation . The combination emergency buses, will be fully the offsi te sourc e(s), which provide power to the plant and maintain safe shutdown cap~ble of supporting the equipment required to achieve during postu lated accid ents and trans ients .

former (#10 and The plant facto rs consi st of the statu s of the Startup Trans forme r (#101 and #201)

1. 20) load tap changers (LTCs), the statu s of the Safeg uard Trans buses on the Safeguard Buses load tap changers CLTCs), and the align~ent of emergency dered operable, bo~h of its (101-Bus and 201-Bus). For an offsi te source to be consi us, #20 AND #201 for the respe ctive LTCs (#10 AND #101 for the source to the 101-B atic. For the third offsi te source to the 201-Bus) must be in servi ce, and in autom connected Safeguard source (from 66 kV System) to be considered operable, the automatic. There is a Transformer (#101 or #201) LTC must be in servi ce and in and the allowable post dependency between the -alignment of the emergency buses contingency volta ge drop percentage.

time) and the post The grid facto rs cons ist of actual grid voltage level s Creal trip contingency voltage drop percentage value.

by the voltage The minimum offsi te source voltage level s are estab lishe d wi]l notif y LGS when (TSO) regul ation calcu latio n, The transmission system opera tor an agreed upon limit is approached.

lated value The post trip contingency percentage voltage drop is a calcu ing of one of the the tripp determined by the TSO that would occur as a resul t of agreed upon limit is exceeded.

Limerick gene rator s. The TSO will notif y LGS when an table percentage voltage drop The voltage regul ation calcu latio n estab lishe s the accep depen dent upon plant based upon plant confi gurat ion; the accep table value is confi gurat ion.

Due to the 20 Source being derived from the terti ary of system the 4A and 48 kV and the 500 kV trans form er, its opera bility is influenced by both the by230the 230 kV system.

system. The 10 Source oper abili ty is only influenced B 3/4 8-1 Amendment No.~ . 44, ~

LIMERICK - UNIT 1 ECR 00 00937, fCR 99 00692, ECR 05-00297

3/4.8 ELECTRICAL POWER SYSTEMS BASES 3/4.8.1. 3/4.8.2. and 3/4.8.3 A.C. SOURCES. D.C. SOURCES. and ONSITE POWER DISTRIBUTION SYSTEMS The anticipated post trip contingency voltage drop for the 66 kV Source (Transformers 8A/8B) is calculated to be less than the 230 kV and 500 kV systems.

This is attributed to the electrical distance between the output of the Limerick generators and the input to the BA/BB transformers. Additionally, the Unit Auxiliary Buses do not transfer to the BA/SB transformers; this provides margin to the calculated post trip contingency voltage drop limit.

There are various means of hardening the 10 and 20 Sources to obtain additional margin to the post trip contingency voltage drop limits. These means include, but are not limited to, source alignment of the 4 kV buses, preventing transfer of 13 kV

~uses, limiting transfer of selected 13 kV loads, and operation with 13 kV buses on the offsite sources. The specific post trip contingency voltage drop percentage limits for these alignments are identified in the voltage regulation calculation, and controlled via plant procedures. There are also additional restrictions that can be applied to these limits in the event that an LTC is taken to manual, or if the bus alignment is outside the Two Source rule set.

LGS unit post trip contingency voltage drop percentage calculations are performed by the PJM Energy Management System (EMS). The PJM EMS consists of a primary and backup system. LGS will be notified if the real .time contingency analysis capability of PJM is lost. Upon receipt of this notification, LGS is to request PJM to provide an assessment of the current condition of the grid based on the tools that r-;_:_..,.___'

PJM has available. The determination of the operability of the offsite.sources would ~.

consider the assessment provided by PJM and whether the current condition of the grid is bounded by the grid studies previously performed for LGS.

Based on specific design analysis, variations to any of these parameters can be determined, usually at the sacrifice of another parameter, based on plant conditions. Specifics regarding these variations must be controlled by plant procedures or by operability determinations, backed by specific design calculations:

The ACTION requirements specified for the levels of degradation of the power sources provide restriction upon continued facility operation commensurate with the level of degradation. The OPERABILITY of the power sources are con-sistent with the initial condition assumptions of the safety analyses and are based upon maintaining at least two of the onsite A.C. and the corresponding D.C. power sources and associated distribution systems OPERABLE during accident conditions coincident with an assu~ed loss-of-offsite power and single failure of the other onsite A.C. or D.C. source. At least two onsite A.C. and their corresponding D.C. power sources and distribution systems providing power for at least two ECCS divisions (1 Core Spray loop, 1 LPCI pump and 1 RHR pump in suppression pool cooling) are required for design basis accident mitigation as discussed in UFSAR Table 6.3-3.

LIMERICK - UNIT 1 B 3/4 8-la Amendment No.~.~. -+/--e4 EGR GG GG9d7, EGR 99 GGeB2, EGR Ge GG297 ECR 09-00284

3/4.8 ELECTRICAL POWER SYSTEMS

)

s--v-s-=r-fM5-(--ent--'i-fltl-&1*-------

A. C. sou RC ES

• D. C:-S-00 RCE S an d-ONStT--n:>OWt-it-frtS-fR-Ii3ttH-eN-RHRSW and ESW 0n site A.C. opera bility requirements for common systems such as statem ents.

are addressed in the appro priate system speci ficati on action A.C. Sources diesel As requir ed by Speci ficati on 3.8.1 .1, Action e, when one or more to verify ement gener ators are inope rable, there is an additi onal ACTION requir devic es, that that all requir ed systems, subsystems, trains , components, and of emergency power, depend on the remaining OPERABLE diesel generators as a source a four train

• are also OPERABLE. The LPCI mode Of the RHR system is considered for LPCI is not n

system, of which only two trains are requir ed. The verifi catio ement is intended requir ed until two diesel generators are inope rable. This requir resul t in a to provide a.ssurance that a loss-o f-offs ite power event will not period when one or complete loss of safety function of critic al system s during the as used in this more of the diese l gener ators is inope rable. The term verify other information to conte xt means to admin istrati vely check by examin ing logs or or other determine if certai n components are out-o f-serv ice for maintenance nts needed to reason s. It does not mean to perform the surve illanc e*requ ireme demonstrate the OPERABILITY of the component.

Speci ficati on Speci ficati on 3.8.1 .1, Action i, prohi bits the applic ation of assoc iated an increa sed risk 3.0.4 .b to an inope rable diesel gener ator. There is tion in the with enteri ng an OPERATIONAL CONDITION or other speci fied condi tem and the provis ions of Appli cabili ty with an inope rable diesel gener ator subsys CO~DIT ION or other Spec; .ficat ion*3 .0.4.b , which allow entry into an OPERA TIONAL ng Condi tion for Opera tion speci fied condi tion in the Appli cabili ty with the Limiti rable system s and not met after performance of a risk assessment addressing inope components, should not be applied in this circumstance.

not exist on If it can be determined that the cause of the inope rable EOG doesthe EDG start then the remaining opera ble EDG(s), based on a common-mode evalu ation, cannot otherwise be test (SR 4.8.1 .1.2.a .4) does not have to be performed. If it not exist on the determined that the cause of the initia l inope rable EOG does test suffic es to provide remaining EDG(s), then satisf actor y performance of the start If the cause of the assurance of continued opera bility of the remaining EDG(s). the EDG(s) shall be initia l inope rabili ty exists on the remaining operable EDG(s),

statement for multi ple declar ed inope rable upon discovery and the appro priate action EOG is restor ed to inope rable EDGs shall be entere d. In the event the inope rable .1.2.a .4) or common-opera ble status prior to completing the EDG start test (SR 4.8.1 the pla~t corre ctive mode failur e evalu ation as required in Speci ficati on 3.8.1 .1, e possi bility .

action.program shall continue to evalu ate the commo n-mode failur const raint imposed by However, this continued evalu ation is not subje ct to the time rable EOG action the action statem ent. The provis ions contained in the inope are based on Gener ic Letter 93-05, requirements that avoid unnecessary EOG testin g illanc e Requirements "Line-Item Technical Speci ficati ons Improvement to Reduce Surve for Testin g During Power Opera tion," dated Septem ber 27, 1993.

B 3/4 8-lb ECR 00 00937, ECR 99 00e82, LIMERICK - UNIT 1 Amendment No . .J:.e.4-, -+/--&9-, ~

ECR 09-00284

3/4.8 ELECTRICAL POWER SYSTEMS A.C. SOURCES, Q.C. SOURCES. and ONSITE POWER DISTRIBUTION SYSTEMS (Continued)

The time, voltage, and frequency acceptance cr1ter1a specified for the EOG single largest post-accident load rejection test (SR 4.8.1.1.2.e.2) are derived from Regulatory Guide 1.9, Rev. 2, December 1979, recommendations. The test i~

acceptable if the EDG speed does not exceed. the nominal (synchronous) speed plus 75% of the difference between nominal speed and the overspeed trip setpoint, or 115% of nominal, whichever is lower. This computes to be 66.5 Hz for the LGS EDGs. The RHR pump motor represents the single largest post-accident load. The 1.8 seconds specified is equal to 60% of the 3-second load sequence interval associated with sequencing the next load following the RHR pumps in response to an undervoltage on the electrical bus concurrent with a LOCA. This provides assurance that EOG frequency does not exceed predetermined limits and that frequency stability is sufficient to support proper load sequencing following a rejection of the largest single load.

o.c. sources With one division with one or two battery chargers inoperable (e.g., the voltage limit of 4.8.2.1.a.2 is not maintained), the ACTIONS provide a tiered response that focuses on returning the battery to the fully charged state and restoring a fully qualified charger to OPERABLE status 1n a reasonable time period.

Action a.1 requires that the battery terminal voltage be restored to greater than or equal to the minimum established float voltage within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. This time (?'-*.

provides for returning the inoperable charger to OPERABLE status or providing an \l.

alternate means of restoring battery terminal voltage to greater than or equal to the minimum established float voltage. Restoring the battery ter.minal voltage to*

greater than or equal to the minimum esta.bl i shed fl oat voltage provides good assurance that, within 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />, the battery will be restored to its fully charged condition (Action a.2) from any discharge that might have occurred due to the charger inoperability.

A discharged battery having terminal voltage of at least the minimum established float voltage indicates that the battery 1s on the exponential charging current portion (the second part) of its recharge cycle. The time to return a battery to its fully charged state under this condition is simply a function of the amount of the previous discharge and the recharge characteristic of the battery.

Thus there is good assurance of fully recharging the battery within 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />, avoiding a premature shutdown with its own attendant risk.

If established battery terminal float voltage cannot be restored to greater than or equal to the minimum established float voltage within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, and the charger is not operating in the current-limiting mode, a faulty charger is .

indicated. A faulty charger that is incapable of maintaining established battery terminal float voltage does not provide assurance that it can revert to and operate properly in the current limit mode that is necessary during the recovery period following a battery discharge event that the DC system is designed for.

LIMERICK - UNIT 1 B 3/4 8-lc gcR oo 00967, gcR 99 Goas2~

Amendment No. ,l.e4, ~ . 189

3/4,8 ELECTRICAL POWER SYSTEMS

)

A.C. SOURCES. D.C. SOURCES. and ONSITE POWER DISTRIBUTION SYSTEMS. (Continued)

If the charger is operating in the current limit mode after 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> that is an its capaci ty margin s will be indica tion that the batter y is partia lly discharged and condit ion in this case is a reduced. The time to return the battery to its fully charged amount of loads on the associ ated DC function of the batter y charger capacity, the e charac teristi c of the system, the amount of the previous discharge, and th~ recharg and th~re is not adequa te assura nce that it batter y. The charge time can be extensive, can be recharged within 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> (Action a.2).

Action a.2 requir es that the battery float* curre~ t be verifie d that, for Divisions 1 and tes if the batter y 2 as~ 2 amps, and for Divisions 3 and 4 as~ 1 amp. This indica r, it has now been had been discharged as the result of the inoperable batter y charge the batter y float fully recharged. If at the expiration of the initia l 18 hour2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> period problems.

curren t is not within limits this indicates there may be additional battery Action a.3 limits the restora tion time for the inoperable battery charger to 7 ng batter y terminal days. This* action is applicable if an altern ate means of restori float voltag e has been used voltag~ to greate r than or equal to the minimum establ ished 7 days reflec ts a reasonal:lle (e.g., balance of plant non-Class lE batter y charge r). The time to effect restor ation of the qualif ied batter y charger to o*PERABLE status With one or more *cells in one or more batter ies in one*division < of 2.07 V, the within 2 hours, verifi tation the required batter y cell is degraded. Per Action b.l, terminal voltage batter y charger OPERABILITY is made by monitoring the battery by monito ring the batter y float (4.8.2 .1.a.2 ) and of the overal l battery state of charge charge curren t (4.8.2 .1.a.1 ). This asrures that there is sti'l *suffic ient batter y capaci ty to perform the intended function. Therefore, withforonea or more cells in one or more batter ies< 2.07 V, continued operation is permitted limite d period up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Division 1 or 2 with float curren t> 2 amps, or Divisio n 3 or 4 with float curren t

> 1 amp, indica tes that a partia l discha rge of the batter y capaci ty has occurred. This may be due to a temporary loss of a batter y charger or possib ly due to one or more batter y cells in a low voltage condition reflec ting some loss of capacity. Per Action b.2, within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> verifi cation of the required batter y charge r OPERABILITY is made by monitoring the batter y termin_al voltage.

Since Actions b.1 and b.2 only specify "perform," a failurnot e of 4.8.2. 1.a.1 or 4.8.2. 1.a.2 acceptance criter ia does not result in thisapprop Action being met. However, riate Action (s), depending on if one of the Surveillance Requirements is failed the the cause of the failur es, is also entered.

If the Action b.2 condition is due to one or more cells in a low voltage condit ion but still greate r than 2.07 V and float voltage is found hours to be satisfa ctory, this is not indica tion of a substa ntially discharged batter y and 18 is a reasonable time prior to declar ing t~e battery. inoperable.

With one or more batter ies in one divisio n with one or more cells electr olyte level above the top of the plates , but below the minimu m establ ished design limits (i.e.,

greate r than minimum level indica tion mark), the bOtteryb.3, still retain s suffic ient*

within 31 days the minimum capaci ty to perform the intended functi on.* Per Action re-est ablish ed.

stabl ished design limits for electr olyte level must be B 3/4 8-ld ECR OD 00937, ECR 99 00e82, LIMERICK - UNIT 1 Amendment No. 164

3/4.8 ELECTRICAL POWER SYSTEMS A.C. SOURCES. D.C, SOURCES. and ONSITE POWER DISTRIBUTION SYSTEMS (Continued)

With electrolyte level below the top of the plates there is a potential for dryout and plate degradation. Action b.3 addresses this potential (as well as provisions in Specification 6.8.4.h, "Battery Monitoring and Maintenance Program"). Within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> level is required to be restored to above the top of the plates. The Action requirement to verify that there is no leakage by visual inspection and the Specification 6.8.4.h item to initiate action to equalize and test in accordance with manufacturer's recommendation are taken from Annex 0-of IEEE Standard 450-1995. They are performed following the restoration of the electrolyte level to above the top of the plates. Based on the re5ults of the manufacturer's recommended testing the battery may have to be declared inoperable and the affected cell(s) replaced.

Per Action b.4, with one or more batteries in one division with pilot cell temperature less than the minimum established design limits, 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is allowed to restore the temperature to within limits. A low electrolyte temperature limits the current and power available. Since the battery is sized with margin, while battery capacity is degraded, sufficient capacity exists to perform the intended function and the affected battery is not required to be considered inoperable solely as a result of the pilot cell temperature not met.

Per Action b.5, with one or more batteries in more than one division with battery parameters not within limits there is not sufficient assurance that battery capacity has not been affected to the degree that the batteries can still perform their required function, given that multiple divisions are involved. With multiple divisions involved, this potential could result in a total loss of function on multiple systems that rely rr_*~--,

upon the batteries. The longer restoration times specified for battery parameters on one \\,_

division not within limits are therefore not appropriate, and the parameters must be restored to within limits on all but one division within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

When any battery parameter is outside the allowances of Actions b.l, b.2, b~3.

b.4, or b.5, sufficient capacity to supply the maximum expected load requirement is not ensured *and a 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> restoration time is appropriate. Additionally, discovering 'one or more batteries in one division with one or more battery cells float voltage less than 2.07 V and float current greater than limits indicates that the battery capacity may not be sufficient to perform the intended functions. The battery must therefore be restored within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

The OPERABILITY of the minimum specified A.C. and D.C. power sources and associated distribution systems during shutdown and refueling ensures that (1) the facility can be maintained in the shutdown or refueling condition for extended time periods and (2) sufficient instrumentation and control capability is available for monitoring and maintaining the unit status.

The surveillance requirements for demonstrating the OPERABILITY of the diesel generators are in accordance with the recommendations of Regulatory Guide 1.9, "Selection of Diesel Gener~tor Set Capacity for Standby Power Supplies," March 10, 1971, Regulatory Guide 1.137 "Fuel-Oil Systems for Standby ~'~sel Generators,"

Revision l, October 1979 and Regulatory Guide 1.108, LIMERICK - UNIT 1 B 3/4 8-le eGR 00 00967, aGR gg 00a82, Amendment No.~

ECR 09-00284

ELECTRICAL POWER SYSTEMS BASES

)

A.C. SOURCES. D.C. SOURCES. and ONSITE POWER DISTRIBUTION SYSTEMS (Continued)

"Periodic Testing of Diesel Generator Units Used as Onsite Electric Power Systems at Nuclear Power Plants," Revision l, August 1977 except for paragraphs C.2.a(3), C.2.c(l), C.2.c(2), C.2.d(3) and C.2.d(4), and the periodic testing will be performed in accordance with the Surveill,ance Frequency Control Program.

The exceptions to Regulatory Guide 1.108 allow for gradual loading of diesel generators during testing and decreased surveillance test frequencies (in response to Generic Letter 84-15). The single largest post-accident load on each diesel generator is the RHR pump.

The Surveillance Requirement for removal of accumulated water from the fuel oil storage tanks is for preventive maintenance. The presence of water does not necess~rily represent failure of the Surveillance Requirement, provirled the accumulated water is removed during performance of the Surveillance.

Accumulated water in the fuel oil storage tanks constitutes a collection of water at a level that can be consistently and reliably measured. The minimum level at which accumulated water can be consistently and reliably measured in the fuel oil storage tank sump is 0.25 inches. Microbiological fouling is a major cause of fuel oil degradation. There are numerous bacteria that can grow in fuel oil and cause fouling, but all must have a water environment in order to survive.

Removal of accumulated water from the fuel storage tanks once every (31) days eliminates the necessary environment for bacterial survival. This is the most effective means of controlling microbiological fouling. In addition, it eliminates the potential for water entrainment in the fuel oil during DG operation. Water may come from any of several sources, including*condensation, ground water, rain water, contaminated fuel oil, and from breakdown of the fuel oil by bacteria.

Frequent checking for and removal of accumulated water minimizes fouling and provides data regarding the watertight integrity of the fuel oil system. The Surveillance Frequencies are established by Regulatory Guide 1.137.

The surveillance requirements for demonstrating the OPERABILITY of the units batteries are in accordance with the recommendations of IEEE Standard 450-1995, "IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented Lead-Acid Batteries for Stationary Applications."

Verifying battery float current while on float charge (4.8.2.1.a.1) is used to determine the state of charge of "the battery. Float charge is the condition in which the charger is supplying the continuous charge required to overcome the internal losses of a battery and maintain the battery in a charged state. The float current requirements are based on the float current indicative of a charged battery.

Use of float current to determine the state of charge of the battery is consistent with IEEE Standard 450-1995.

This Surveillance Requirement (4.8.2.1.a.1) states the float current requirement is not required to be met when battery terminal voltage is less than the minimum established float voltage of 4.8.2.1.a.2. When this float voltage is not maintained, the Actions of 3.8.2.1 Action a., provides the necessary and appropriate verifications of the battery condition. Furthermore, the float current limits are established based on the float voltage range and is not directly applicable when this voltage is not maintained.

~-*

LIMERICK - UNIT 1 B 3/4 8-2 Amendment No. 4-Q, l, m., ~. J.e-4.,186 correction ltr. 6/19/95 ECR 97 01067

AUS 2 1 201III ECR 00-00937

ELECTRICAL POWER SYSTEMS BASES A.C. S0t1RCTS-;-D~~RCTS, and DNSI IE POWER DISTRTBUTTOW-SYSTrnS-rContinued-)- - - - - - - - -

Verifying, per 4.8.2 .. 1.a.2. battery terminal voltage while on float charge for the batteries helps to ensure the effectiveness of th~ battery chargers, which support the ability of the batteries to perform their intended function. Fl oat charge is the condition in which the charger is supplying the continuous charge required to overcome the interhal losses of a battery and maintain the battery in a fully charged state while supplying the continuous steady state loads of the associated DC subsystem. On float charge, battery cells will receive adequate current to optimally charge the battery. The voltage requirements are based on the minimum float voltage established by the battery manufacturer (2.20 Vpc, average, or 132 Vat the battery terminals). This voltage maintains the battery plates in a condition that supports maintaining the grid life (expected to be approximately 20 years).

Surveillance Requirements 4.8.2.1.b.1 and 4.8.2.1.c require verification that the cell float voltages are equal to or greater than 2.07 V.

The limit specified in 4.8.2.1.b.2 for electrolyte level ensures that the plates suffer no physical damage and maintains adequate electron transfer capability.

Surveillance Requirement 4.8.2.1.b.3 verifies that the pilot cell temperature is greater than or equal to the minimum established design limit Ci .e., 60 degrees Fahrenheit). Pilot cell-electrolyte temperature is maintained above this temperature to assure the battery can provide the required current and voltage to meet the design requirements. Temperatures lower than assumed in battery sizing calculations act to inhibit .or reduce battery capacity.

Surveillance Requirement 4.8.2.1.d.1 verifies the design capacity of the battery chargers. According to Regulatory Guide 1.32, the battery charger supply is recommended to be based on the largest combined demands of the various steady state loads and the charging capacity to restore the battery from the design minimum charge state to the fully charged state, irrespective of the status of the unit during these demand occurrences. The minimum required amperes and duration ensures that these requirements can be satisfied.

Surveillance Requirement 4.8.2.1.d.1 requires that each battery charger be capable of supplying the amps listed for the specified charger at the minimum established float voltage for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The ampere requirements are based on the output rating of the chargers. The*voltage requirements are based on the charger voltage level after a response to a loss of AC power. This time period is sufficient for the charger temperature to have stabilized and to have been maintained for at least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

A battery service test, per 4.8.2.1.d.2, is a special test of the battery's capability, as found, to satisfy .the design requirements (battery duty cycle) of the DC electrical power system. The discharge rate and test length corre~ponds to the design duty cycle requirements as specified in the UFSAR.

LIMERICK - UNIT 1 B 3/4 8-2a Amendment No. ~ , -l-84 ,18 6 ECR 97 Q1067

ELECTRICAL POWER SYSTEMS

.;;*B=AS==E=S=---oc:i::a::i::::iac::::::c:i:i::::c:========-======~=***=**--*=-*-=~=-==-=--==ca:,=- ====-== ~~ ,

A.C. SOURCES. D.C. SOURCES. and ONSITE POWER DISTRIB0TI0N SYSTEMS (Continued)

A battery performance discharge test (4.8.2.1.e and f) is a test of constant current capacity of a battery, norm~lly done in the as found condition, after having been in service, to detect. any change in the capacity determined by the acceptance test. The test is intended to determine overall battery degradation due to age and usage. Degradation Cas used in 4. 8. 2 .1. f) is indicated when the battery capacity drops more than 10% from its capacity on the previous performance test, or is below 90% of the manufacturer's rating.

• Either the battery performance discharge test or the modified performance discharge test is acceptable for satisfying 4.8.2.1.e and 4.8.2.1.f; however, only the modified performance discharge test may be used to satisfy the battery service test requirements of 4.8.2.1.d.2.

((~--

LIMERICK - UNIT 1 8 3/4 8-2b Amendment No. 164

ELECTRICAL POWER SYSTEMS

-~

3/4.8.4 ELECTRICAL EQUIPMENT PROTECTIVE DEVICES The RPS Electric Power Monitoring System is provided to isolate the RPS bus from the RPS/UPS inverter or an alternate power supply in the event of overvoltage, undervoltage, or underfrequency. This system protects the loads connected to the RPS bus from unacceptable voltage and frequency conditions. The essential equipment powered from the RPS buses includes the RPS logic, scram solenoids. and valve isolation logic. .

The Allowable Values are derived from equipment design limits. corrected for calibration and instrument errors. The trip setpoints are then determined, accounting for the remaining instrument errors (e.g .* drift). The trip setpoints deriveq in this manner provide adequate protection and include allowances for instrumentation uncertainties. calibration tolerances. and instrument drift.

The Allowable Values for the instrument settings are based on the RPS providing power within the design ratings of the associated RPS components (e.g .*

RPS logic, scram ~olenoids). The most limiting voltage requirement and associated line losses determine the settings of the electric power monitoring instrument channels.

LIMERICK - UNIT 1 B 3/4 8-3 Amendment No.~. 9J., ~

LtF 11/18/98, -1#

Associated with Amendment No. 209

THIS PAGE INTENTIONALLY LEFT BLANK

~--. 3/4.9 REFUELING OPERATIONS BASES 3/4. 9.1 REACTOR MODE 'SWITCH Locking the OPERABLE reactor aode sw;tch fn the Shutdown or Refuel position, as specified, ensures that the restrictions an control rod withdrawal and refueling platform movement during the refueling operations are properly activated. These canditions reinforce the refueling procedures and reduce the probability of inadvertent criticality, damage to reactor internals or fuel assellblies, and exposure of personnel to excessive radioactivity.

3/4.9.2 INSTRUMENTATION The- OP-ERASIUTY- of-. at least twa source range monitors ensures* that* redundant monitoring capability is available to detect changes in the reactivity condition of the core. The minimum count rate is not required when sixteen or fewer fuel assemblies are in the *core. During a typical core reloading, two, three or four irradiated fuel assemblies will be loaded ~djac*nt ta each SJitfto* produce greater than the minimum required count rate. Loading sequences are selected to provide for a continuous multiplying medium to be established between ttie required oper-able SRMs and the location of the core alteration. This enhances the ability

-of the SRMs to respond to the loading of each fuel assembly. During a core un-loading, the last fuel to be removed is that fue1 adjacent to the SRMs.

3/4.9.3 CONTROL ROD POSITION The requirement that all control rods be inserted during other CORE ALTERATIONS ensures that fuel ~ill not be loaded into a cell vithout a control rod.

3/4.9.4 DECAY TIME The 11iniaun requirement for reactor subcriticalfty prior to fuel aovement ensures that sufficient time has elapsed ta a11ow the radioactive decay of the short lived fission products. Thh decay tiae 1s consistent with the assump-tions used in the accident analyses. -

• 3/4.9.5 C0"4UNICATIOHS The requirement for cD111unicat1ons capability ensures that refueling station personnel can be praaptly informed of significant changes in the facility status or core reactivity condition during movement of fuel within the reactor pressure vessel.

Mff111n7 LIMERICK - VNIT l B 3/4 9-1 Amendment No. 4

REFUELING OPERATIONS BASES (Continued) 3/4.9.6 REFUELING PLATFORM The OPERABILITY requirements ensure that Cl) the refueling platform will be used for handling control rods and fuel assemblies within the reactor pressure vessel, (2) each hoist has sufficient load capacity for handling fuel assemblies and control rods, (3) the core internals and pressure vessel are protected from excessive lifting force in the event they are inadvertentl y engaged during lifting operations, and (4) inadvertent criticality will not occur due to fuel being loaded into a unrodded cell.

Inadvertent criticality is prevented by the refueling interlocks that block unacceptable operations (e.g., loading fuel into a cell with a control rod withdrawn or withdrawal of a rod from the core while the grapple is over the core and loaded with fuel). The hoist loaded values identified in Sections 4.9 . 6.lb and 4.9.6.lc support the refueling interlock logic by ensuring that the hoist fuel loaded switches function with a load lighter than the weight of a single fuel assembly in water.

Load values represent fuel (load) on the grapple. The values of 485 +/- 50 pounds and 550 + 0, -115 pounds are both less than the weight of a single fuel assembly in water attached to the grapple. These load values ensure that as soon as a fuel assembly is grappled and lifted, the*refuelin g interlocks (control rod block and bridge motion interlock) are enforced as required. The hoist load weighing system is compensated for mast weight to ensure that lifting of components other than fuel assemblies (e.g., blade guides) do not cause inadvertent control rod blocks or bridge motion stops.

3/4.9.7 CRANE TRAVEL* SPENT FUEL STORAGE POOL The restriction on movement of loads in excess of the nominal we1ght of a fuel assembly and associated lifting device over other fuel assemblies in the storage pool ensures that in the event this load is dropped 1) the activity release will be limited to that contained in a single fuel assembly, and 2) any possible distortion of fuel in the storage racks will not result in a critical array. This assumption is consistent with the activity release assumed in the safety analyses.

3/4.9.8 and 3/4,9.9 WATER LEVEL

• REACTOR VESSEL and WATER LEVEL* SPENT FUEL STORAGE POOL The restrictions on minimum water level ensure that sufficient water depth is available to remove 99% of the assumed 10% iodine gap activity released from the rupture of an irradiated fuel assembly. This minimum water depth is consistent with the assumptions of the accident analysis.

3/4.9.10 CONTROL ROD REMOVAL These specificatio ns ensure that maintenance or repair of control rods or control rod drives will be performed under conditions that limit the probability of inadvertent criticality. The requirements for simultaneous removal of more than one control rod are more stringent since the SHUTDOWN MARGIN specification provides for the core to remain subcritical with only one control rod fully withdrawn.

LIMERICK* UNIT 1 B 3/4 9-2 Amendment No. ECR 06-00389

REFUELING OPERATIONS BASES (Continued) 3/4.9.11 RESIDUAL HEAT REMOVAL AND COOLANT CIRCULATION Irradiated fuel in the shutdown reactor core generates heat during the decay of fission products and increases the temperature of the reactor coolant. This decay heat must be removed by the RHR system to maintain adequate reactor coolant temperature.

RHR shutdown cooling is comprised of four (4) subsystems which make two (2) loops. Each loop consists of two (2) motor driven pumps, a heat exchanger, and associated piping and valves. Both loops have a common suction from the same recirculation loop. Two (2) redundant, manually controlled shutdown cooling subsystems of the RHR system provide decay heat removal. Each pump discharges the reactor coolant, after circulation through the respective heat exchanger, to the reactor via the associated recirculation loop. The RHR heat exchangers transfer heat to the RHR Service Water System.

-An OPERABLE RHR shutdown cooling subsystem consists of one Cl) OPERABLE RHR pump, one Cl) heat exchanger, and the associated piping and valves. The requirement for having one Cl) RHR shutdown cooling subsystem OPERABLE ensures that 1) sufficient cooling capacity is available to remove decay heat and maintain the water in the reactor pressure vessel below 140°F, and 2) sufficient coolant circulation would be available through the reactor core to assure accurate temperature indication.

Management of gas voids is important to RHR Shutdown Cooling Subsystem OPERABILITY .

. The requirement to have two (2) RHR shutdown cooling subsystems OPERABLE when there is less than 22 feet of water above the reactor vessel flange ensures that a single failure of the operating loop will not result in a complete loss of residual heat removal capability. With the reactor vessel head removed and 22 feet of water above the reactor vessel flange, a large heat sink is available for core cooling. Thus, in the event of a failure of the operating RHR subsystem, adequate time is provided to initiate alternate methpds capable of decay heat removal or emergency procedures to cool the core.

To meet the LCD of the two (2) subsystems OPERABLE when there is less than 22 feet of water above the reactor vessel flange, both pumps in one Cl) loop or one (1) pump in each of the two (2) loops must be OPERABLE. The two (2) subsystems have a common suction source and are allowed to have a common heat exchanger and common discharge piping. Additionally, each shutdown cooling subsystem can provide the required decay heat removal capability; however, ensuring operability of the other shutdown cooling subsystem provides redundancy.

The required cooling capacity of an alternate method of decay heat removal should be ensured by verifying its capability to maintain or reduce reactor coolant temperature either by calculation (which includes a review of component and system availability to verify that an alternate decay heat removal method is available) or by demonstration. Decay heat removal capability by ambient losses can be considered in evaluating alternate decay heat removal capability.

LIMERICK - UNIT 1 B 3/4 9-2a Amendment No. gg., ~. -l-l-9-,

ECR 01 00386, ECR 06 00389, Associated with Amendment 216

REFUELING OPERATIONS 3/4.9.11 RESIDUAL HEAT REMOVAL AND COOLANT CIRCULATION (Continued) er:**

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 non-condensible gas into the reactor vessel. This surveillance verifies that the RHR Shutdown Cooling System piping is sufficiently filled with water prior to placing the system in operation when in OPCON 5. The RHR Shutdown Cooling System is OPERABLE when it is sufficiently filled with water to ensure that it can reliably perform its intended function.

The RHR Shutdown Cooling System is a manually initiated mode of the RHR System that is aligned for service using system operating procedures that ensure the RHR shutdown cooling suction and discharge flow paths a*re sufficiently filled with water.

An RHR Shutdown Cooling sub-system that is already in operation at the time of entry into the APPLICABILITY is OPERABLE. For an idle RHR Shutdown Cooling subsystem, the surveillance is met through the performance of the operating procedures that place the RHR Shutdown Cooling subsystem in service.

With the required decay heat removal subsystem(s) inoperable and the required alternate method(s) of decay heat removal not available in accordance with Action "a",

additional actions are required to minimize any potential fission product release to the environment. This includes ensuring Refueling Floor Secondary Containment is OPERABLE; one (1) Standby Gas Treatment subsystem is OPERABLE; and Secondary Containment isolation capability (i.e., one (1) Secondary Containment isolation valve cc~

and associated instrumentation are OPERABLE or other acceptable administrative controls to assure isolation capability) in each associated penetration not isolated that is assumed to be isolated to mitigate radioactive releases. This may be performed as an administrative check, by examining logs or other information to determine whether the components are out of service for maintenance or other reasons. It is not necessary to perform the Surveillances needed to demonstrate the OPERABILITY of the components.

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

If no RHR subsystem is in operation, an alternate method of coolant circulation is required to be established within one (1) hour. The Completion Time is modified such that one (1) hour is applicable separately for each occurrence involving a loss of coolant circulation.

((_~

LIMERICK - UNIT 1 B 3/4 9-3 Amendment No. -+/--+/--9-, -**

gcR 06 00329, Associated with Amendment 216

3/4 .1 Q SPEC JAL TEST EXCEPTIONS BASES

)

3.4.10.l PRIMARY CONTAINMENT INTEGRITY The requ;rement for PRIMARY CONTAINMENT INTEGRITY ;snot applicable during the period when open vessel tests are being performed during the low power PHYSICS TESTS.

3/4.JQ.2 ROD WOBIH MINIMIZER In order ,to perform the tests required in *the technical specificat;ons it is necessary to bypass the sequence restrafots on control rod movement. The additional surveillance requirements ensure that the specifications on heat generation rates and shutdown margin requirements are n*ot exceeded during the period when these tests are being performed and that individual rod worths do not exceed the values assumed in the safety analysis.

3/4.10.3 SHUTDOWN MARGIN DEMONSTRATIONS Performance of shutdown margin demonstrations with the vessel head removed requires additional restrictions in order to ensure that criticality does not occur. These additional restri-ctions are specified in this LCO.

3/4.10.4 RECIRCULATION LOOPS This special test exception permits reactor criticality under no flow conditions and is required to perform certain *startup and PHYSICS TESTS while at low THERMAL POWER levels.

3/4.10.5 OXYGEN CONCENTRATION Relief from the oxygen concentration specifications is necessary in order to provide access to the primary containment dur;ng the initial startup and testing phase of operation. Without this access the startup and test program could be restricted and delayed.

3/4.10.6 TRAINING STARTUPS This special test exception permits training startups to be performed with the reactor vessel depressurized at low THERMAL POWER and temperature while*

controlling RCS temperature with one RHR subsystem aligned in the shutdown cooling mode in order to minimize contaminated water discharge to the .

radioactive waste dispostl system.

3/4.10.7 RES&RVED - CURRENTLY NOT USED LIME&ICK - UNIT 1 B 3/4 10-1 Amendment No. Y7, '!a, .133 FEB 1 1* 1999

3/4.10 SPECIAL TEST EXCEPTIONS

• • • • • • • 3/4*.10.8 INS-ERY*ICE LEAKANP HYDRBSTATI'C TESTING This special test exception permits certain reactor ~ool~nt ~ressure tests to be performed in OPERATIONAL CONDITION 4 when the metallurgical characteristics of the reactor pressure vessel (RPV) or plant temperature control capabilities during these tests require the ¢ressure testing at temperatures greater thah 200°F ahd less than or equal to 212°F (normally corresponding to OPERATIONAL CONDITION 3). The additionally imposed OPERATIONAL CONDITION 3 requirements for SECONDARY CONTAINMENT INTEGRITY provide conservatism in response to an operational ~vent.

', ,~

Invoking the requirement for Refueling Area Secondary Containment *Integrity along with the requirement for Reactor Enclosure Secondary Cont~inment Int~grity applies the requirements for Reactor Enclosure Secondary Containment Integrity to an extended area encompassing Zones 1 and 3. Operations with the Potential for Draining the Vessel, Core alterations, and fuel handling are prohibited in this secondary containment configuration. Drawdown and inleakage testing performed for the combined zone system alignment shall be considered adequate to d~monstraie integrity of the combined zones.

Inservice hydrostatic testing and inservice leak pressure tests required by Section XI of the American Soc*iety of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code are performed prior to the reactor going critical after a refueling outage. The minimum temperatures (at the required pressures) allowed for these tests are determined from the RPV pressure and temperature (P/T) limits required by LCO 3.4.6, Reactor Coolant System Pressure/Temperature Limits. These limits are conservatively based on the fracture toughness of the reactor vessel, taking into account anticipated vessel neutron fluence. With increased reactor fluence over time, the minimum allowable vessel temperature increases at a given pressure.

([,**

LIMERICK - UNIT 1 B 3/4 10-2 Amendment No. -lJ.J tG~ 99 00864, 167

3/4.11 RADIOACTIVE EFFLUENTS HitS 3/4.11.1.l and 3/4.11.l.2 (Deleted)

THE INFORMATION FROM THESE SECTIONS HAS BEEN RELOCATED TO THE ODCM.

/ . )

\~

LIMERICK - UNIT 1 B 3/4 11-1

• Amendment *No. A48 I.

JAK O2. \99\

• RADIOACTIVE EFFLUENTS 3/4.11.1.3 (Deleted) - INFORMATION FROM THIS SECTION RELOCATED TO THE ODCM.

3/4.11.1.4 LIQUID HOLDUP TANKS The tanks listed in this specification include all those outdoor radwaste tanks that are not surrounded by liners, dikes, or walls capable of holding the tank contents and that do not have tank overflows and surrounding area drains connected to the liquid radwaste treatment system.

Restricting the quantity of radioactive material contained in the specified tanks provides assurance that in the event of an uncontrolled release of the tanks' contents, the resulting concentrations would be less than 10 times the limits of 10 CFR Part 20, Appendix B, Table 2. Column 2, at the nearest potable water supply and the nearest surface water supply in an UNRESTRICTED AREA.

3/4.11.2.1 (Deleted) - INFORMATION FROM THIS SECTION RELOCATED TO THE ODCM.

LIMERICK - UNIT 1 B 3/4 11-2 Amendment No.~. 4,g Associated with Amendment No. 187

RADIOACTIVE. EFFLUENTS BASES 3/4.11.2. 2 thro~gh 3/4.11.2. 4 (Deleted)

THE INFORMATION FROM THESE SECTIONS HAS BEEN RELOCATED TO THE ODCM.

LIMERICK - UNIT 1 B 3/4 11-3 Amendment No. 4-8 JAN O2 1991

RADIOACTIVE EFFLUENTS C

3/4.11.2.5 (Deleted) - INFORMATION FROM THIS SECTION RELOCATED TO THE TRM.

c:

LIMERICK - UNIT 1 B 3/4 11-4 Amendment No. ,4.g, 228

RADIOACTIVE EFFtUENfS

.;.;;..;;~~~~----c~*-

BASES

"~;_)~ - ~ - - . . - - - . - - ; - 7 ~ = ~ - - - - - - - - - - - - - - - -

\> 3/4.11 .2.6 MAIN CONDENSER Restric ting the gross radioa ctivity rate of noble gases from the main condenser provides reasona ble assurance that the total body exposure ta. an individual at the exclusi on area boundary will not exceed a small fractio n of the limits of 10 CFR Part 100 in the event this effluen t is inadvertently discharged directl y to th~*

environment without trea"tment. This specifi cation implements the General Design Criter ia 60 and 64 of Appendix A to 10 CFR Part 50. requirements of 3/4 11.2.7 , 3/4 11.3, and 3/4 11.4 (Deleted) - INFORMATION FROM THESE SECTIONS RELOCATED TO THE OOCM OR PCP.

LIMERICK - UNIT"l B 3/4 11-5 Amendment No.48 JAN O2 1991

r )

R / 1/1)

.) 3/4.12 RADIOLOGICAL ENVIRONMENTAL MONITORING

, ---~BA~S~E!::*::::::::::~~:::::::::=::==:::::::::::=::=::=::=::=:::==:==:==:===============

Section 3/4.12 (Deleted)

THE INFORMATION FROM THIS SECTION HAS BEEN RELOCATED TO THE ODCM. BASES PAGE B 3/4 12-2 HAS BEEN INTENTIONALLY OMITTED.

LIMERICK - UNIT 1 B 3/4 12*1 Amendment No.42 JAN O2 1991

PAra: JNI'ENTIONALLY LEFT B~.NK LIMERICK GENERATING STATION UNIT 2 TECHNICAL SPECIFICAtlON PAGE REVISION LIST Index Amendment Nos.

48 ii 168 iii 48 iv Original Issue V 4 vi 48 vii 147 viii 147 ix 147 X 191 xi 160 xii 107 xiii 135 xiv 150 xv 170 xvi 95 xvii 191 xviii 48 xix 191 xx Associated with Amendment No. 178 xxi 149 xxii 95 xxiii 191 xxiv 11 XXV Original Issue xxvi 138 .

xxvii 153 xxviii 181 Section 1.0 Definitions 1-1 Original Issue 1-2 146 1-3 188 1-4 153 1-5 107 1-6 192 1-7 192 1-8 148 1-9 34 1-10 112 LIMERICK - UNIT 2 - A- REVISED THRU AMENDMENT 196 EXCEPT IMPLEMENTATION OF AMENDMENT 190

LIMERICK GENERATING STATION UNIT 2 TECHNICAL SPECIFICATION PAGE REVISION LIST Index Amendment Nos. (

Section 2.0 Safety Limits and Limiting Safety System Settings 2-1 187 2-2 Original Issue 2-3 109 2-4 163 2-4a Original Issue Bases for Section 2.0 B 2-1 1.83 B 2-2 ECR LG 12-00035 B 2-3 Original Issue B 2-4 Original Issue B 2-5 Original Issue B 2-6 139 B 2-7 Associated with Amendment 163 B 2-7a Associated with Amendment 163 B 2-8 52 B 2-9 Original Issue 82-10 139 (

Section 3.0 and 4.0 Limiting Conditions for Operation and Surveillance Requirements 3/4 0-1. 189 3/4 0-1a 181 3/4 0-2 189 3/4 0-3 188 3/4 1-1 Original Issue 3/4 1-2 168 3/4 1-3 140 3/4 1-4 147 3/4 1-5 147 3/4 1-6 147 3/4 1-7 Original Issue 3/4 1-8 132 3/4 1-9 105 3/4 1-10 147 3/4 1-11 132 3/4 1-12 Original Issue 3/4 1-13 132 3/4 1-14 147 3/4 1-15 Original Issue LIMERICK - UNIT 2 REVISED THAU AMENDMENT 196 EXCEPT IMPLEMENTATION OF AMENDMENT 190

LIMERICK GENERATING STATION UNIT 2 TECHNICAL SPECIFICATION PAGE REVISION LIST Index Amendment Nos.

3/4 1-16 Original Issue 3/4 1-17 Original Issue 3/41-18 147 3/4 1-19 163 3/41-20 195 3/4 1-21 195 3/41-22 Original Issue 3/4 2-1 147 3/4 2-2 4 3/4 2-3 thru 3/4 2-6a Deleted 3/4 2-7 48 3/42-8 48 3/42-9 147 3i/4 2-10 4 3/4 2-1 Oa thru 3/4 2-11 Deleted 3/4 2-12 147 3/4 3-1 196 3/4 3-1a 147 3/43-2 139 3/4 3~3 52 3/43-4 1.61 3/43-5 163 3/4 3-6 139 3/43-7 163 3/43-8 196 3/4 3-8a 163 3/43-9 132 3/4 3-10 147 3/43-11 52 3/4 3-12 Original Issue 3/4 3-13 Original Issue 3/4 3-14 74 3/4 3~15 74 3/4 3-16 146 3/4 3-17 107 3/4 3-18 183 3/4 3-19 174 3/4 3-20 174 3/4 3-21 74 3/4 3-22 74 3/4 3-23 175 3/4 3-24 93 3/4 3-25 93 LIMERICK - UNIT 2 - C- REVISED THRU AMENDMENT 196 EXCEPT IMPLEMENTATION OF AMENDMENT 190

LIMERICK GENERATING STATION UNIT 2 TECHNICAL SPECIFICATION PAGE REVISION LIST Index Amendment Nos. (

3/4 3-26 107 3/4 3-27 147 3/4 3-28 147 3/4 3-29 147 3/4 3-30 147 3/4 3-31 147 3/4 3-32 147 3/4 3-33 185 3/4 3-34 Original Issue 3/4 3-35 185 3/4 3-36 120 3/4 3-36a 120 3/4 3-37 Original Issue 3/4 3-38 Original Issue 3/4 3-39 93 3/4 3-40 147 3/4 3-41 147 3/4 3-42 147 3/4 3-43 33 3/4 3-44 51 3/4 3-45 147 (

3/4 3-46 163 3/4 3-47 147 3/4 3-48 163 3/4 3-49 Original Issue 3/4 3-50 Original Issue 3/4 3-51 147 3/4 3-52 147 3/4 3-53 185 3/4 3-54 17 3/4 3-55 Original Issue 3/4 3-56 147 3/4 3-57 147 3/4 3-58 139 3/4 3-59 109 3/4 3-60 163 3/4 3-60a 139 3/4 3-60b 3 3/4 3-61 147 3/4 3-62 147 3/4 3-63 147 3/4 3-64 146 3/4 3-65 146

LIMERICK* UNIT 2

• D. REVISED THAU AMENDMENT 196 EXCEPT IMPLEMENTATION OF AMENDMENT 190

LIMERICK GENERATING STATION UNIT 2 TECHNICAL SPECIFICATION PAGE REVISION LIST Index Amendment Nos.

3/4 3-66 147 3/4 3-67 147 3/4 3-68 153 3/4 3-69 thru 3/4 3-72 Deleted 3/4 3-73 11 3/4 3-74 thru 3/4 3-75 Deleted 3/4 3-76 147 3/4 3-77 Original Issue 3/4 3-78 Original Issue 3/4 3-79 Original Issue 3/4 3-80 47 3/4 3-81 Original Issue 3/4 3-82 Original Issue 3/4 3-83 147 3/4 3-84 147 3/4 3-85 152 3/4 3-86 135 3/4 3-87 152 3/4 3-88 147 3/4 3 79 3/4 3-90 147 3/4 3-91 147 3/4 3-92 68 3/4 3-92a thru 3-96 Deleted 3/4 3-97 117 3/4 3-98 11 3/4 3-99 thru 3/4 3-102 Deleted 3/4 3-103 191 3/4 3-104 Deleted 3/4 3-105 Deleted 3/4 3-106 Deleted 3/4 3-107 Deleted 3/4 3-108 Deleted 3/4 3-109 11 3/4 3-110 153 3/4 3-111 Deleted 3/4 3-112 147 3/4 3-113 55 3/4 3-114 Original Issue 3/4 3-115 147 LIMERICK - UNIT 2 - E- REVISED THRU AMENDMENT 196 EXCEPT IMPLEMENTATION OF AMENDMENT 190

LIMERICK GENERATING STATION UNIT 2 TECHNICAL SPECIFICATION PAGE REVISION LIST Index Amendment Nos. (_

3/4 4-1 163 3/4 4-1a 139 3/44-2 163 3/44-3 139 3/44-4 157 3/4 4-4a 157 3/44-5 147 3/44-6 Original Issue 3/44-7 147 3/4 4-8 169 3/4 4-8a 167 3/4 4-9 144 3/4 4-10 147 3/4 4-11 144 3/4 4-12 136 3/4 4-13 thru 3/4 4-14 Deleted 3/4 4-15 136 3/4 4-16 Original Issue 3/4 4-17 147 3/4 4-18 147 3/4 4-19 147 3/4 4-20 125 3/4 4-21 130 3/4 4-22 147 3/4 4-23 132 3/4 4-24 160 3/4 4-25 178 3/4 4-26 178 3/4 5-1

• 153 3/4 5-2 92 3/4 5-3 172 3/4 5-4 178 3/4 5-5 147 3/4 5-6 59 3/4 5-7 147 3/4 5-8 Original Issue 3/4 5-9 147

( ..___/

LIMERICK* UNIT 2

• F. REVISED THRU AMENDMENT 196 EXCEPT IMPLEMENTATION OF AMENDMENT 190

LIMERICK GENERATING STATION UNIT 2 TECHNICAL SPECIFICATION PAGE REVISION LIST Index Amendment Nos.

3/4 6-1 147 3/4 6-2 107 3/4 6-3 146 3/4 6-4 81 3/4 6-5 132 3/4 6-6 147 3/4 6-7 188 3/4 6-8 172 3/4 6-9 147 3/4 6-10 153 3/4 6-11 147 3/4 6-12 Original Issue 3/4 6-13 147 3/4 6-14 147 3/4 6-15 178 3/4 6-16 178 3/4 6-17 153 3/4 6-18 147 3/4 6-19 107 3/4 6-20 thru 3/4 6-43a Deleted 3/4 6-44 9 3/4 6-45 147 3/4 6-46 192 3/4 6-47 192 3/4 6-48 147 3/4 6-49 153 3/4 6-50 147 3/4 6-51 153 3/4 6-51 a 153 3/4 6-52 146 3/4 6-52a 147 3/4 6-53 147 3/4 6-54 86 3/4 6-55 147 3/4 6-56 147 3/4 6-57 135 3/4 6-58 147 3/4 6-59 147 3/4 7-1 165 3/4 7-1 a 165 3/4 7-2 147 3/4 7-3 165 LIMERICK - UNIT 2 -G- REVISED THRU AMENDMENT 196 EXCEPT IMPLEMENTATION OF AMENDMENT 190

LIMERICK GENERATING STATION UNIT 2 TECHNICAL SPECIFICATION PAGE REVISION LIST Index Amendment Nos. (

3/4 7-4 147 3/4 7-5 147 3/4 7-6 149 3/4 7-6a 153 3/4 7-7 149 3/4 7-8 149 3/4 7-9 178 3/4 7-10 147 3/4 7-11 184 3/47-11a 184 3/47-11b Deleted 3/4 7-12 184 3/4 7-13 Deleted 3/4 7-14, Deleted 3/4 7-15 Deleted 3/4 7-16 Deleted 3/4 7-17 147 3/4 7-18 172 3/4 7-19 68 3/4 7-20 thru 3/4 7-32 Deleted 3/4 7-33 147 3/4 8-1 165 3/4 8-1a 150 3/4 8-2 165 3/4 8-2a 150 3/4 8-3 150 3/4 8-4 150 3/4 8-5 147 3/4 8-6 147 3/4 8-7 147 3/4 8-7a 150 3/4 8-8 150 3/4 8-9 154 3/4 8-10 126 3/4 8-10a 126 3/4 8-11 147 3/4 8-12 147 3/4 8-13 126 3/4 8-14 126 3/4 8-14a 126 3/4 8-15 Original Issue LIMERICK* UNIT 2 - H. REVISED THRU AMENDMENT 196 EXCEPT IMPLEMENTATION OF AMENDMENT 190

LIMERICK GENERATING STATION UNIT 2 TECHNICAL SPECIFICATION PAGE REVISION LIST Index Amendment Nos.

3/4 8-16 Original Issue 3/4 8-16a 102 3/4 8-17 147 3/4 8-18 Original Issue 3/4 8-18a Original Issue 3/4 8-19 102 3/4 8-20 147 3/4 8-21 153 3/4 8-22 thru 3/4 8-26 Deleted 3/4 8-27 170 3/4 8-28 147 3/4 9-1 112 3/4 9-2 147 3/4 9-3 147 3/4 9-4 147 3/4 9-5 147 3/4 9-6 Original Issue 3/4 9-7 147 3/4 9-8 8 3/4 9-9 8 3/4 9-10 147 3/49-11 147 3/4 9-12 147 3/4 9-13 Original Issue 3/4 9-14 147 3/4 9-15 Original Issue 3/4 9-16 147 3/4 9-17 178 3/4 9-18 178 3/4 10-1 147 3/4 10-2 Original Issue 3/4 10-3 147 3/4 10-4 147 3/4 10-5 147 3/4 10-6 147 3/4 10-7 Original Issue 3/4 10-8 Original Issue 3/4 10-9 95 3/411-1 11 3/4 11-2 thru 3/4 11-6 Deleted 3/4 11-7 147 3/4 11-8 11

.,, 3/4 11-9 thru* 3/4 11-14 Deleted LIMERICK - UNIT 2 - I- REVISED THRU AMENDMENT 196 EXCEPT IMPLEMENTATION OF AMENDMENT 190

LIMERICK GENERATING STATION .

UNIT 2 TECHNICAL SPECIFICATION PAGE REVISION LIST Index Amendment Nos. (

3/411-15 191 3/4 11-16 191 3/411-17 11 3/411-18 11 3/4 11-19 thru 11-20 Deleted 3/4 12-1 11 3/4 12-2 thru 12-14 Deleted Bases for Sections 3.0 and 4.0 B 3/4 0-1 Original Issue B 3/4 0-2 Associated with Amendment 189 B 3/4 0-3 Associated with Amendment 189 B 3/4 0-3a Associated with Amendment 189 B 3/4 0-3a1 Associated with Amendment 189 B 3/4 0-3b Associated with Amendment 189 B 3/4 0-3b1 Associated with Amendment 189 B 3/4 0-3c Associated with Amendment 181 B 3/4 0-3d Associated with Amendment 181 B 3/4 0-3e Associated with Amendment 188 B 3/4 0-3f Associated with Amendment 181 (

B 3/4 Q-4 Associated with Amendment 189 B 3/4 0-4a Associated with Amendment 189 B 3/40-5 132 B 3/40-6 Associated with Amendment 188 B 3/4 1-1 Associated with Amendment 168 B 3/41-2 131 B 3/4 1-2a 140 B 3/41-3 147 B 3/41-4 Associated with Amendment 195 B 3/4 1-5 ECR LG 14-00055 B 3/4 2-1 48 B 3/4 2-2 48 B 3/42-3 14 B 3/4 2-4 ECR LG 12-00035 B 3/42-5 48 .

B 3/4 3-1 147 B 3/4 3-1a Associated with Amendment 196 B 3/4 3-1b Associated with Amendment 196 B 3/4 3-1c Associated with Amendment 196 B 3/4 3-1d Associated with Amendment 196 83/43-18 Associated with Amendment 196 B 3/4 3-1f Associated with Amendment 196

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B 3/43-2 147 B 3/4 3-3 147 LIMERICK - UNIT 2 -J- REVISED THAU AMENDMENT 196 EXCEPT IMPLEMENTATION OF AMENDMENT 190

LIMERICK GENERATING STATION UNIT 2 TEC_HNICAL SPECIFICATION PAGE REVl$10N LIST.

Index Amendment Nos.

B 3/4 3-3a Associated with Amendment 163 83/43-4 147 8 3/43-5 ECR LG 09-00585 8 3/4 3-5a ECR LG 09-00585 8 3/43-6 147 83/43-7 191 8 3/43-8 Origir:1al Issue 8 3/43-9 109 8 3/4 4-1 *Associated with Amendment 157 8 3/44-2 Associated with Amendment 157 8 3/44-3 Associated with Amendment 169 8 3/4 4-3a Associated with Amendment 169 8 3/4 4-3b Associated with Amendment 169 8 3/4 4-3c Associated with Amendment 167 8 3/4 4-3d Associated with Amendment 167 8 3/4 4-3e Associated with Amendment 167 8 3/44-4 1.32 8 3/44-5 ECR 04-00575, Rev. 1 8 3/44-6 Associated with Amendment 160

---B-3/4-4-6a----- - -Associated-with Ame11dment-1 8 3/44-7 111 8 3/4 4-8 . 51 8 3/4 5-1 Associated with Amendment 178 8 3/45-2 Associated with Amendment 178 8 3/45-3 Associated with Amendment 178 8 3/4 5-4 Associated with Amendment 178 8 3/4 6-1 ECR 11-00395 8 3/46-2 147 83/4 6-3 Associated with Amendment 178 8 3/4 6-3a Associated with Amendment 178 8 3/4 6-3b Associated with Amendment 178 8 3/4 6-4 147 8 3/4 6-4a 110 8 3/4 6-5 ECR LG 09-00052 8 3/4 6-5a Associated with Amendment 192 8 3/4 6-6 86 8 3/4 6-7 135 8 3/4 7-1 149 8 3/4 7-1a 149 8 3/4 7-1b 149 8 3/4 7-1c Associated with Amendment 178 8 3/4 7-1d Associated with Amendment 178 8 3/4 7-2 184 8 3/4 7-3 184 8 3/4 7-3a Original Issue LIMERICK - UNIT 2 - K- REVISED THRU AMENDMENT 196 EXCEPT IMPLEMENTATION OF AMENDMENT 190

LIMERICK GENERATING STATION UNIT 2 TECHNICAL SPECIFICATION PAGE REVISION LIST Index Amendment Nos. (

8 3/4 7-4 68 8 3/4 7-5 16 8 3/4 8-1 ECR 05-00297 8 3/4 8-1a ECR 09-00284 8 3/4 8-1b ECR 09-00284 8 3/4 8-1c 150 8 3/4 8-1d 126 8 3/4 8-1e ECR 09-00284 8 3/4 8-2 147 8 3/4 8-2a 147 8 3/4 8-2b 126 83/4 8-3 Associated with Amendment 170 8 3/4 9-1 Original Issue 8 3/4 9-2 ECR 06-00391 8 3/4 9-2a Associated with Amendment 178 8 3/49-3 Associated with Amendment 178 8 3/410-1 Original Issue 8 3/4 10-2 130 8 3/4 11-1 11 83/411-2 Associated with Amendment 148 8 3/411-3 11 (

8 3/411-4 191 8 3/4 11-5 11 8 3/412-1 11 8 3/412-2 Deleted Section 5.0 Design Features 5-1 11 5-2 Original Issue 5-3 Original Issue 5-4 Original Issue 5-5 Original Issue 5-6 11 5-7 Original Issue 5-8 51 5-9 Original Issue Section 6.0 Administrative Controls 6-1 60 6-2 159 6-3 159 6-4 2 ~

6-5 60 LIMERICK - UNIT 2 - L- REVISED THAU AMENDMENT 196 EXCEPT IMPLEMENTATION OF AMENDMENT 190

LIMERICK 'GENERATING STATION UNIT 2 TECHNICAL SPECIFICATION PAGE REVISION LIST

\ ,7 Index Amendment Nos.

6-6 194 6-7 138

. 6-8 138 6-9 138 6-10 138 6-11 60 6-12 138 6-12a 138 6-13 138 6-14 129 6-14a 158 6-14b 11 6-14c 151 6-14d 184 6-14e 191 6-15 172 6-16 172 6-17 100 6-18 11 6-18a 161 6-19 138 6-20 138 6-20a 100 6-21 100 6-21a 138 6-22 149 6-23 181 6-24 181 LIMERICK - UNIT 2 - M- REVISED THRU AMENDMENT 196 EXCEPT IMPLEMENTATION OF AMENDMENT 190

BASES FOR SECTION 2.0 SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS I

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AUG 2 5 1989

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The BASES contained in succeeding pages summarize the reasons for the Specifications in Section 2.0, but in accordance with 10 CFR 50.36 are not part of these Technical Specifications.

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AU6 2 5 1989

2.1 SAFETY LIMITS BASES

'* 2.0 INTRODUcrION The fuel cladding, reactor pressure vessel and primary system piping are the principle barriers to the release of radioactive materials to the environs.

Safety* Limits are established to protect the integrity of these barriers during normal plant operations and anticipated transients. The fuel cladding iritegrity Safety Limit is set such that no fuel damage is calculated to occur if the limit is not violated. Because fuel *damage is not directly observable; a step'-back approach is used to establish a Safety Limit such that more than 99:.9% of the fuel rods avoid transition boiling. Meeting the Safety Limit can be demonstrated by analysis that confirms less than 0.1% of fuel rods in the core are susceptible to transition boiling br by demonstrating that the MCPR is not less than the values specified in Specification 2.1.2 for two recirculation loop operation and for single recirculation loop operation. Less than 0.1% of*fuel rods in transition boiling*and MCPR greater than the values specified for two recirculation loop operation and for single recirculation loop operation represents a conservative margin relative to the conditions required to *maintain fuel cladding integrity. The fuel cladding is one of the physical barriers which separate the radioactive materials from the environs. The integrity of this

• cladding barrier is related to its relative freedom from perforations or cracking.

Although some* corrosion or use related cracking may occur during the life of the cladding, fission product migration. from this source is incrementally cumulative and continuously measurable. Fuel cladding perforations, however, can result from thermal stresses which occur from reactor operation significantly above design conditions and the Limiting Safety System Settings. While fission product migration from cladding perforation is just as measurable as that from use related I cracking, the thermally caused cladding perforations signal a threshold beyond

"'""' which still greater thermal stresses.may cause gross rather than incremental cladding deterioration. Therefore, the fuel cladding Safety Limit is defined with a margin to the conditions which would produce onset of transition boiling, MCPR of 1.0. These conditions represent a significant departure from the condition intended by design for planned operation.

2.1.1 THERMAL POWER, Low Pressure or Low Flow The use of the (GEXL) correlation is not valid for*all critical power calculations at pressures below 700 psia or core flows less than 10% of rated flow. Therefore, the fuel cladding integrity Safety Limit is established by other means. This is done by establishing a limiting condition on core THERMAL POWER with the following basis. Since the pressure drop in the bypass region is essentially all elevation head, the core pressure drop at low power and flows will always be greater than 4.5 psi. Analyses show that with a bundle flow of 28 x 103 lb/hr, bundle pressure drop is nearly independent of bundle power and has a value of *3,5 psi. Thus, the bundle flow with a 4.5 psi driving head will be greater than 28 x 103 lb/hr. Full scale ATLAS test data taken at pressures from 14.7 psia to 800 psia indicate that the fuel assembly critical power at this flow is approximately 3.35 MWt. *With the design peaking factors, this corresponds to a THERMAL POWER of more than 50% of RATED THERMAL POWER. Thus, a THERMAL POWER limit of 25% of RATED THERMAL POWER for reactor pressure. below 700 psia is conservative.

LIMERICK - UNIT 2 B 2-1 Amendment No. 14, 83, &r, -91, -3+/-4,

-lrr, ~ ' ECR LG 12 00035, 183

SAFETY LIMITs*

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• ,.. .::..:,/

2, L 2

• THERMAL POWER.* Hi qh* Pressure and High EJ ow*

. . . The-.fuel* c:1addin'g**integ.rity Sa,fety Limit is set:*such th.at rio.fuei°*d_amage:.

is.: calculated to* occur 1f* {he .l i tntt . fs ..not: ~ i cH ated:*. *S1 nee the parameters* *' .*.*

• whfch:** result: in* .fuel', :damage.:*. are. not*, direct 1Y observab 1e during. reactor** .. operat 16n, the: thermal, and.hydr.aulic:'.concti'tfons* resul.t.1hg.in a*departure: from riucleate*:*, .. \

• boiling -.have: been<used**, to:. mark .the,*. beginning* bf:.'the -region .. where', fuel.-'damag~ :.. .

could* occur;:; .. Al.though* 1t

• 1s:**recogn.fzect.>.that: a:.. departure .. from** nucl eate .. boi ling.:,.,.

wo1;Jld, not, necessar.Jly *r$sult::".:in . dam_age to: BWRifuel .:rods,:*the:-cri_tical power. .. a,t*.*

Whfch*: bo1, l1 ng

• transition-.. i Si'-._Ca lcul ated** to .O<;:cur.*. has.;. ~een-: ~dopted as: a convenient li~it~ .Howeverj the=uncertainties:in*monitor1n~~thacore:operat1n~*state an~.,

in the procedures, used. to*.-calcul'ate the* critical. power* result iri an. *.uncerta1n~y***

in* the valLie:of*.the critical power. *Therefore, the. fuel cladding integrity*. *.

Safety L1m1t*is defined . . as:.the.CPR in the.-11miting*:fuel as~emblY:.for*which more*

than* 99.9% -of the *fuel, r9ds,.1 ri-the core are, expect'ed.-.to* av9i d boili ng .. transit1 on

• Gonsidering*:tha*power di~tribution,within.the. cqre*an~ a]l:uncerta1nties.. . .

. . .. rhe :*an*a.1 ys*es ... tiia*t* ci~~o~:~~*r-~te/ 1e~( th~*n o /ii*.~~ t.u.e1 *. . ~oq~: .e~:t~r:*. ~~-ansi t 1.on

.*.bot-ling and determine:the:Safety*Limit.MCPR:are.performed using.a s'l;atist1ca1 * .

ap*proach* that**comb1nes* an: of* the. uncertainties* 1n *oper*at1ng parameters and .*.the.

procedures*.used to calculate:cr1.t1cal power.. The*analys1s methods* used to.-perform.

-these calculations*are. descr1b~~*1n Refeten6~ 1.. *

• -.L ReJerence:

1. "General Electric Standard Appl1cat1on for Reactor Fuel," NEDE-24011-P-A.

(latest approved revision).

LIMERICK - UNIT 2 B 2-2 ECR LG 12-00035

INTENTIONALLY LEFT BLANK LIMERICK - UNIT 2 . B 2-3 AUG 2 5 1989

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INTENTIONALLY LEFT BLANK

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LIMERICK - UNIT 2 *s 2-4 . AUG 2 5 1989

SAFETY LIMITS BASES 2.1.3 REACTOR COOLANT. SYSTEM PRESSURE The Safety Limit for the reactor coolant system pressure has been selected such that it is at a pressure below which it can be shown that the integri ty of the system is not endangered. The reactor pressure vessel is designed to Section III of the ASME Boiler and Pressure Vessel Code 1968pres-Edition , including Addenda through Summer 1969, which permits a *maximum sure transie nt of 110%, 1375 psig, of design pressure 1250 psig. The Safety Limit of 1325 psig, as measured by the reactor vessel steam dome pressure indicato r, is equivalent to 1375 psig at the lowest elevatio n of the reactor coolant system. The reactor coolant system is designed to the ASME Boi'ler1977 and Pressure Vessel Code, 1977 Edition, including Addenda ttir_ougb Summer for the reactor recircu lation piping, which permits a maximum pressure transien t of 110%, 1375 psig of design pressure, 1250 psig for s~ction piping and 1500 the psig for dis,charge piping. The pressure Safety Liniit is .selected to beVessel Code lowest transie nt overpressure allowed by the ASME Boiler and *Pressure Section III, Class I.

2.1.4 REACTOR VESSEL WATER LEVEL With fuel in the reactor vessel during periods when the reactor is shutdown, consideration must be given to water level requirements due tothethe effect of decay heat. If the water level should drop below the top of heat is

.active irradiat ed fuel during this period, the ability to remove decay cladding reduced. This reduction in cooling capability could lead to elevated less temperatures and clad perfora tion in the event that the water level became hed at than two-thirds of the core height. The Safety Limit has been establis the top of the active irradiat ed fuel to provide a point which can be monitored an~ also provide adequate margin for effectiv e action.

LIMERICK - UNIT 2 B 2-5 AUG 2 5 1989

2.2 LIMITING SAFETY SYSTEM SETTINGS 2.2.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS (

The Reactor Protection System instrumentation setpoints specified in Table 2.2.1-1 are the values at which the reactor trips are set for each para-meter. The Trip Setpoints have been selected to ensure that the reactor core and reactor coolant system are prevented from exceeding their Safety Limit~

during normal operation and design basis anticipated operational occurrences and to assist in mitigating the consequences of accidents. Operation with a trip set less conservative than its Trip Setpoint but within its specified Allowable Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is equal to or less than the drift allowance assumed for each trip in the safety analyses.

1. Intermediate Range Monitor. Neutron Flux - High The IRM system consists of 8 chambers, 4 in each of the reactor trip systems. The IRM is a 5 decade 10 range instrument. The trip setpoint of 120 divisions of scale is active in each of the 10 ranges. Thus as the !RM is ranged up to accommodate the increase in power level, the trip setpoint is also ranged up. The IRM instruments provide for overlap with both the APRM and SRM systems.

The most significant source of reactivity changes during the power increase is due to control rod withdrawal. In order to ensure that the !RM provides the required protection, a range of rod withdrawal accidents have been analyzed. The results of these analyses are in Section 15.4 of the FSAR. The most severe case involves an initial condition in which THERMAL POWER is at approximatelr 1% of RATED THERMAL POWER. Additional conservatism was taken in this analysis by assuming the IRM channel closest to the control rod bein~ withdrawn is bypassed. The results of this analysis show that the reactor 1s shutdown and peak power is limited to 21% of RATED THERMAL POWER with the peak fuel enthalpy well below the fuel failure threshold of 170 cal/gm.

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Based on this analysis, the !RM provides protection against local control rod errors and continuous withdrawal of control rods in sequence and provides backup protection for the APRM.

2. Average Power Range Monitor The APRM system is divided into four APRM channels and four 2-0ut-Of-4 Voter channels. The four voter channels are divided into two groups of two each, with each group of two providing inputs to one RPS trip system. All four voters will trip (full scram) when any two unbypassed APRM channels exceed their trip setpoints.

APRM trip Functions 2.a, 2.b, 2.c, and 2.d are voted independently from OPRM Upscale Function 2.f. Therefore, any Function 2.a, 2.b, 2.c, or 2.d trip from any two unbypassed APRM channels will result in a full trip in each of the four voter channels. Similarly, a Function 2.f trip from any two unbypassed APRM channels will result in a full trip from each of the four voter channels.

For operation at low pressure and low flow during STARTUP, the APRM Neutron Flux-Upscale (Setdown) scram setting of 15% of RATED THERMAL POWER provides adequate thermal margin between the setpoint and the Safety Limits. The margin acconmodates the anticipated maneuvers associated with power plant startup. Effects of increasing pressure at zero or low void content are minor and cold water from sources available during startup is not much colder than that already in the system. Tempera-ture coefficients are small and control rod patterns are constrained by the RWM. Of all the possible sources of reactivity input, uniform control rod withdrawal is the most probable cause of significant power increase. ( __

LIMERICK - UNIT 2 B 2-6 Amendment No.~. 139

LIMITING SAFETY SYSTEM SETTINGS REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS <Continued)

Average Power Range Monitor (Continued)

Because the flux distribution associated with uniform rod withdrawals does not involve high local peaks and because several rods must be moved to change power by a significant amount, the rate of power rise is very slow. Generally the heat flux is in near equilibrium with the fission rate. In an assumed uniform rod withdrawal approach to the trip level, the rate of power rise is not more than 5% of RATED THERMAL POWER per minute and the APRM system would be more than adequate to assure shutdown before the power could exceed the Safety Limit.

The 15% Neutron Flux - Upscale (Setdown) trip remains active until the mode switch is placed in the Run position.

The APRM trip system is calibrated using heat balance data taken during steady state conditions. Fission chambers provide the basic input to the system and therefore the monitors respond directly and quickly to changes due to transient operation for the case of the Neutron Flux - Upscale setpoint; i.e.,

for a power increase, the THERMAL POWER of the fuel will be less than that indicated by the neutron flux due to the time constants of the heat transfer associated with the fuel. For the Simulated Thermal Power - Upscale setpoint, a time constant of 6 +/- 0.6 seconds is introduced into the flow-biased APRM in order to simulate the fuel thermal transient characteristics. A more conservative maximum value is used for the flow-biased setpoint as shown in Table 2.2.1~1.

A reduced Trip Setpoint and Allowable Value is provided for the Simulated Thermal Power - Upscale Function, applicable when the plant is operating in Single Loop Operation (SLO) per LCD 3.4.1.1. In SLO, the drive flow values (W) used in

- the Trip_Setpoint and Allowable Value equations is reduced by 7.6%. The 7.6% value is established to conservatively bound the inaccuracy created in the core flow/drive flow correlation due to back flow in the jet pumps associated with the inactive recirculation loop. The Trip Setpoint and Allowable Value thus maintain thermal margins essentially unchanged from those for two-loop operation. The Trip Setpoint and Allowable Value equations for single loop operation are only valid for flows down to W= 7.6%. The Trip Setpoint and Allowable Value do not go below 61.5% and 62.0% RATED THERMAL POWER, respectively.* This is acceptable because back flow in the inactive recirculation loop is only an issue with drive flows of approximately 40% or greater (Reference 1).

The APRM setpoints were selected to provide adequate margin for the Safety Limits and yet allow operating margin that reduces the possibility of unneces-sary shutdown.

• The APRM channels also include an Oscillation Power Range Monitor (OPRM)

Upscale Function. The OPRM Upscale Function provides compliance with GDC 10 and GDC 12, thereby providing protection from exceeding the fuel MCPR Safety Limit due to anticipated thermal-hydraulic power oscillations. The OPRM Upscale Function receives input signals from the local power range monitors (LPRMs) within the reactor core, which are combined into "cells" for evaluation by the OPRM algorithms.

References 2, 3 and 4 describe three al9orithms for detecting thermal-hydraulic instability related neutron flux oscillations: the period based detection algorithm, the amplitude based algorithm, and the growth rate algorithm.

All three are implemented in the OPRM Upscale Function, but the safety analysis takes credit only for the period based detection algorithm. The remaining algorithms provide defense in depth and additional protection against unanticipated oscillations. OPRM Upscale Function OPERABILITY for Technical Specification purposes* is based only on the period based detection algorithm.

• LIMERICK - UNIT 2 B 2-7 Amendment 48,~.~.

Associated with Amendment 163

LIMITING SAFETY SYSTEM SETTINGS REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPQINTS (Continued)

Average Power Range Monitor (Continued)

The OPRM Upscale trip output shall be automatically enabled (not bypassed) when APRM Simulated Thermal Power is~ 29.5% and recirculation drive flow is

< 60% as indicated by APRM measured recirculation drive flow. (NOTE: 60%

recirculation drive flow is the recirculation drive flow that corresponds to 60%

of rated core flow. Refer to TS Bases 3/4.3.1 for further discussion concerning the recirculation drive flow/core flow relationship.) This is the operating region where actual thermal-hydraulic instability and related neutron flux oscillations may occur. See Reference 5 for additional discussion of OPRM Upscale trip enable region limits. These setpoints, which are sometimes referred to as the "auto-bypass>> setpoints, establish the boundaries of the OPRM Upscale trip enabled region. The APRM Simulated Thermal Power auto-enable setpoint has 1% deadband while the drive flow setpoint has a 2% deadband. The deadband for these setpoi~ts is established so that it increases the enabled region.

An OPRM Upscale trip is issued from an APRM channel when the period based detection algorithm in that channel detects oscillatory changes in the neutron flux, indicated by the combined signals of the LPRM detectors in a cell, with period confirmations and relative cell amplitude exceeding specified setpoints.

One or more cells in a channel exceeding the trip conditions will result in a channel. trip. An OPRM Upscale trip is also issued from the channel if either the growth rate or amplitude based algorithms detect oscillatory changes in the neutron flux for one or more cells in that channel.

There are four "sets" of OPRM related setpoints or adjustment parameters:

a) OPRM trip auto-enable setpoints for APRM Simulated Thermal Power (29.5%) and recirculation drive flow (60%); b) period based detection algorithm (PBDA)

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confirmation count and amplitude setpoints; c) period based detection algor1thm tuning parameters; and d) growth rate algorithm (GRA) and amplitude based algorithm (ABA) setpoints.

The first set, the OPRM auto-enable region setpoints, are treated as nominal setpoints with no additional margins added as discussed in Reference 5.

The settings, 29.5% APRM Simulated Thermal Power and 60% recirculation drive flow, are defined (limit values) in a note to Table 2.2.1-1. The second set, the OPRM PBDA trip setpoints, are established in accordance with methodologies defined in Reference 4, and are documented in the COLR. There are no allowable values for these setpoints. The third set, the OPRM PBDA "tuning" parameters, are established or adjusted in accordance with and controlled by station procedures.

The fourth set, the GRA and ABA setpoints, in accordance with References 2 and 3, are established as nominal values only, and controlled by station procedures.

3. Reactor Vessel steam Dome Pressure-High High pressure in the nuclear system could cause a rupture to the nuclear system process barrier resulting in the release of fission products. A pressure increase while operating will also tend to increase the power of the reactor by compressing voids thus adding reactivity. The trip will quickly reduce the neutron flux, counteracting the pressure increase. The trip setting is slightly higher than the operating pressure to permit normal operation without spurious trips. The setting provides for a wide margin to the maximum allowable design pressure and takes into account the location of the pressure measurement compared to the highest pressure that occurs in the system during a transient. This trip setpoint is effective at low power/flow conditions when the turbine stop valve and control fast closure trips are bypassed. For a turbine trip or load rejection (

under these conditions, the transient analysis indicated an adequate margin to '--

the thermal hydraulic limit.

LIMERICK* UNIT 2 B 2-?a Amendment 4,g, +Q.9., .J:J.9.,

Associated with Amendment 163

INTENTIONALLY LEFT BLANK LIMITING SAFETY SYSTEM SETTINGS

~BA~S1a:1Es_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _,(

REACTOR PRQTECJION SYSTEM INSTRUMENTATION SETPQINTS (Continued)

4. Reactor YesseJ Water LeyeJ-Low The reactor vessel water level tri~ setpoint has been used in transient analyses dealing with coolant inventory decrease. The scram setting was chosen far enough below the normal operating level to avoid spurious trips but high enough above the fuel to assure that there is adequate protection for the fuel and pressure limits.

5. Main steam Line JsoJation VaJve-CJosure The main steam line isolation valve closure trip was ~rov1ded to limit the amount of fission product release for certain postulatei:f events. The MSIVs are closed automatically from measured parameters such as high steam flow, low reactor water level, high steam tunnel temperature, and low steam line pressure.

The MSIVs closure scram anticipates the pressure and flux transients which could follow HSIV closure and thereby protects reactor vessel pressure and fuel thermal/hydraulic Safety Limits. *

6. DELETED I

7. PcvweJJ Pressure-High High pressure in the drywell could indicate a break in the primary pressure boundary systems or a loss of drywell cooling. The reactor is tri~ped in order (_

to minimize the possibility of fuel damage and reduce the amount of energy being added to the coolant and to the primary containment. The trip setting was selected as low as possible wit_hout causing spurious trips.

FEB 161995 LIMERICK - UNIT 2 B 2-8 Amendment NO. 52

LIMITING SAFETY SYSTEM SETTING BASES REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS (Continued)

8. Scram Discharge Volume Water Level-High The scram discharge volume receives the water displaced by the motion of the control rod drive pistons during a reactor scram. Should this volume fill up to a point where there is insufficient volume to accept the displaced water at pressures below 65 psig, control rod insertion would be hindered. The reactor is therefore tripped when the water level has reached a point high enough to indicate that it is indeed filling up, but the volume is still great enough to accommodate the water from the movement of the rods at pres~ures below 65 psig when they are tripped. The trip setpoint for each scram discharge volume is equivalent to a contained volume of 25.58 gallons of water. *

9. Turbine Stop Valve-Closure The turbine stop valve closure trip anticipates the pressure, neutron flux, and heat flux increases that would result from closure of the stop valves. With a trip setting of 5% of valve closure from full open, the resultant increase in heat flux is such that adequate thermal margins are maintained during the wo!st design basis transient.

,~ 10. Turbine Control Valve Fast Closure, Trip Oil P'ressure-Low The turbfne control valve fast closure trip anticipates the pressure, neutron flux, and heat flux increase that could result from fast closure of the turbine control valves due to load rejection with or without coincident failure of the turbine bypass valves. The Reactor Protection System initiates a trip when fast closure of the control valves is initiated by the fast acting solenoid valves and in less than 30 milliseconds after the start of control.valve fast closure. This is achieved by the action of the fast acting solenoid valves in rapidly reducing hydraulic trip oil pressure at the main turbine control valve actuator disc dump valves. This loss of pressure is sensed by pressure switches whose contacts form the one-out-of-two-twice logic input to the Reactor Protection System. This trip setting, a faster closure time, and a different valv~ characteristic from that of the turbine stop valve, combine to produce transients which are very similar to that for the stop valve.* Relevant transient analyses are discussed in Section 15.2.2 of the Final* Safety Analysis ~eport.

11. Reactor Mode Switch Shutdown Position The reactor mode switch Shutdown position is a redundant channel to the automatic protective instrumentation channels and provides additional manual reactor trip capability.

12. Manual Scram The Manual Scram is a redundant channel to the automatic protective instrumentation channels and provides manual reactor trip capability.

LIMERICK - UNIT 2 B 2-9 AUG 2 5 1923

LIMITING SAFETY SYSTEM SETTING REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS (Continued) (

REFERENCES:

1. NEDC-31300, "Single-Loop Operation Analysis for Limerick Generating Station, Unit l," August 1986.

2. NED0-31960-A, "BWR Owners' Group Long-Term Stability Solutions Licensing Methodology," November 1995.

3. NED0-31960-A, Supplement 1, "BWR Owners' Group Long-Term Stability Solutions Licensing Methodology," November 1995.

4. NED0-32465-A, "Reactor Stability Detect and Suppress Solutions Licensing Basis Methodology for Reload Applications," August 1996.

5. BWROG Letter 96113, K. P. Donovan (BWROG) to L. E. Phillips (NRC),

"Guidelines for Stability Option III 'Enable Region' (TAC M92882),"

September 17, 1996.

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LIMERICK - UNIT 2 B 2-10 Amendment No. 139 I

BASES*FOR SECTIONS 3.0 AND 4.0 LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS I

~

AUG 2 5 1969

(

NOTE The BASES contained in succeeding pages summarize the reasons for the Specifications in Sections 3.0 and 4.0, but in accordance with 10 CFR 50.36 are not part of these Technical Specifications .

C--

~U6 2 5 1989

3/4.0- APPLICABILITY BASES Specifications 3.0.1 through 3.0.4 establish the general requirements applicable to Limiting Conditions for Operation. These requirements are based on the requirements for Limiting Conditions for Operation stated in the Code of Federal Regulations, 10 CFR 50.36(c)(2):

"Limiting Conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When a limiting condition for operation of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specification until the condition can be met."

Specification 3.0.1 establishes the Applicability statement within each individual specification as the requirement for when (i.e., in which OPERATIONAL CONDITIONS or other specified conditions) conformance to the Limiting Conditions for Operation is required for safe operation .of the facility. The ACTION requirements establish those remedial measures that must be taken wjthin specified time limits when the requirements of a Limiting Condition for Operation are not met. It is not intended that the shutdown ACTION. requirement be used as an operation convenience which permits (routine) voluntary removal of a system(s) or component(s) from service in lieu of *other alternatives that would not result in redundant systems or components being inoperable.

There are two basic types of ACTION requirements. The first specifies the remedial measures that permit conti.nued operation of the facility which is not further restricted by the time limits of the ACTION requirements. In this case, conformance to the ACTION requirements provides an acceptable level of safety for unlimited continued operation as long as the ACTION requirements continue to be met. The second type of ACTION requirement specifies a time limit in which conformance*to the conditions of the Limiting Condition for Operation must be met. This time limit is the allowable outage time to restore an inoperable system or component to OPERABLE status or for restoring parameters within specified limits. If these actions are not completed within the allowable outage time limits, a shutdown is required to place the facility in an OPERATIONAL CONDITION or other specified condition in which the specification no longer applies.

The specified time limits of the ACTION requirements are applicable from the point of time it is identified that a Limiting Condition for Operation is not met. The time limits of the ACTION requirements are also applicable when a system or component is removed from service for surveillance testing or investigation of operational problems. Individual specifications may include a specified time limit for the completion of a Surveillance Requirement when equipment is removed from service. In this case, the allowable outage time limits of the ACTION requirements are applicable when this limit expires if the surveillance has not been completed. When a shutdown is required to comply with ACTION requirements, the plant may have entered an OPERATIONAL CONDITION in which a new specification becomes applicable. In this case, the time limits of the ACTION requirements would apply from the point in time that the new specification becomes applicable if the requirements of the Limiting Condition for Operation are not met.

LIMERICK - UNIT 2 B 3/4 0-1

APPLICABILID'

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Specification 3.0.2 establishes that noncompliance with a specification exists when the requirements of the Limiting Condition for Operation are not met and the associated ACTION requirements have not been implemented within the specified time interval, unless otherwise specified. The purpose of this speci.fication is to clarify that (1) implementation of the ACTION requirements

• within the specified time interval constitutes compliance with a specification and (2) completion of the remedial measures of the ACTION requirements is not required when compliance with a Limiting Condition of Operation is restored within the time interval specified in the associated ACTION requirements.

Specification 3.0.3 establishes the shutdown ACTION requirements that must be implemented when a Limiting Condition for Operation is not met and the condition is not specifically addressed by the associated ACTION requirements.

The purpose of this specification is to delineate the time 1imits for placing the unit in a safe shutdown CONDITION when plant operation cannot be maintained within the limits for safe operation defined by the Limiting Conditions for Operation and its ACTION requirements. It is not intended to be used as an operational convenience which permits (routine) voluntary removal of redundant systems or components from service in lieu of other- alternatives that would not result in redundant systems or components being inoperable. One hour is allowed to prepare for an orderly shutdown before initiating a change in plant operation. This time permits the operator to coordinate*t_he reduction in electrical generation with the load dispatcher to ensure the stability and availability of the electrical grid. The time limits specified to enter lower CONDITIONS of operation permit the shutdown to proceed in a controlled and (

orderly manner that is well within the specified maximum cooldown rate and * .

within the cooldown capabilities of the facility assuming only the minimum required equipment is OPERABLE. This reduces thermal stresses on. components of the primary coolant system and the potential for a plant upset that could challenge safety systems under conditions for which this specification applies.

If remedial measures permitting limited continued operation of the facility under the provisions of the ACTION requirements are completed, the shutdown may be terminated. The time limits of the ACTION requirements are applicable from the point in time there was a failure to meet a Limiting Condition for Operation. Therefore, the shutdown may be terminated if the ACTION requirements have been met, the ACTION is no longer applicable, *or time limits of the ACTION requirements have not expired, thus providing an allowance for the completion of the required actions.

The time limits of Specification 3.0.3 allow 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br /> for the plant to be in COLD SHUTDOWN when a shutdown is required during POWER operation. If the plant is in a lower CONDITION of operation when a shutdown is required, the time limit for entering the next lower CONDITION of operation applies.

However, if a lower CONDITION of operation is entered in less time than allowed, the total allowable time to enter COLD SHUTDOWN, or other OPERATIONAL CONDITION, is not reduced. For example, if STARTUP is entered in 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, the time allowed to enter HOT SHUTDOWN is the next 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> because the total time to enter HOT SHUTDOWN is not reduced from the allowable limit of 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />.

Therefore, if remedial measures are completed that would permit a return to POWER operation, a penalty is not incurred by having to enter a lower CONDITION of operation in less than the total time allowed.

LIMERICK - UNIT 2 B 3/4 0-2 Associated with Amendment No 189

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APPLICABILITY BASES The same principle applies with regard to the allowable outage time limits of the ACTION requirements, if compliance with the ACTION requirements for one specificatio n results in entry into an OPERATIONAL CONDITION or condition of operation for another specificatio n in which the requirements of the Limiting Condition for Operation are not met. If the new specificatio n becomes applicable in less time than specified, the difference may be added to the allowable outage time limits of the second specificatio n. However, the allowable outage time of ACTION requirements for a higher CONDITION of operation may not be used to extend the allowable outage time that is applicable when a Limiting Condition for Operation is not met in a lower CONDITION of operation.

The shutdown requirements of Specificatio n 3.0.3 do not apply in CONDITIONS 4 and 5, because the ACTION requirements of individual specificatio ns define the remedial measures to be taken.

Specificatio n 3.0.4 establishes limitations on changes in OPERATIONAL CONDITIONS or other specified conditions in the Applicabilit y when a Limiting Condition for Operation is not met. It allows placing the unit in an OPERATIONAL CONDITION or other specified condition stated in that Applicabilit y (e.g., the Applicabilit y desired to be entered) when unit conditions are such that the requirements of the Limiting Condition for Operation would not be met, in accordance with either Specificatio n 3.0.4.a, Specificatio n 3.0.4.b, or Specificatio n_3.0.4.c.

Specificatio n 3.0.4.a allows entry into an OPERATIONAL CONDITION or other specified condition in the Applicabilit y with the Limiting Condition for Operation not met when the associated ACTION requirements to be entered following entry into the OPERATIONAL CONDITION or other specified condition in* the Applicabilit y will permit continued operation within the MODE or other specified condition for an unlimited period of time. Compliance with ACTIONS requirements that permit continued operation of the unit for an unlimited period of time in an OPERATIONAL CONDITION or other specified condition provides an acceptable level of safety for continued operation. This is without regard to the status of the unit before or after the OPERATIONAL CONDITION change. Therefore, in such cases, entry into an OPERATIONAL CONDITION or other specified condition in the Applicabilit y may be made and the Required Actions followed after entry into the Applicabilit y.

For example, LCO 3.0.4.a may be used when the Required Action to be entered states that an inoperable instrument channel must be placed in the trip condition within the Completion Time. Transition into a MODE or other specified condition in the Applicabilit y may be made in accordance with LCO 3.0.4 and the channel is subsequently placed in the tripped condition within the Completion Time, which begins when the Applicabilit y is entered. If the instrument channel cannot be placed in the tripped condition and the subsequent default AmON ("Required Action and associated Completion Time not met") allows the OPERABLE train to be placed in operation, use of LCO 3.0.4.a is acceptable because the subsequent ACTIONS to be entered following entry into the MODE include ACTIONS (place the OPERABLE train in operation) that permit safe plant operation for an unlimited period of time in the MODE or other specified condition to be entered.

Specificatio n 3.0.4.b allows entry into an OPERATIONAL CONDITION or other specified condition in the Applicabilit y with the Limiting Condition for Operation not met after performance of a risk assessment addressing inoperable systems and components, consideratio n of the results, determination of the acceptabilit y of entering the OPERATIONAL CONDITION or other specified condition in the Applicabili ty, and establishmen t of risk management actions, if appropriate.

LIMERICK - UNIT 2 B 3/4 0-3 Amendment No. -lr4, r, Associated with Amendment No. 189

APPLICABILID' The risk assessment may use quantitative, qualitative, or blended approaches, (

and the risk assessment will be conducted using the plant program, procedures, and criteria in place to implement 10 CFR 50.65(a)(4), which requires that risk impacts of maintenance activities be assessed and managed. The risk assessment, for the purposes of Specification 3.0.4.b, must take into account all inoperable Technical Specification equipment regardless of whether the equipment is included in the normal 10 CFR 50.65(a)(4) risk assessment scope.

The risk assessments will be conducted using the procedures and guidance endorsed by Regulatory Gui de 1.182, "Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants." Regulatory Guide 1.182 endorses the guidance in Section 11 of NUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants." These documents address general guidance for conduct of the risk assessment, quantitative and qualitative guidelines for establishing risk management actions, and example risk management actions. These include actions to plan and conduct other activities in a manner that controls overall risk, increased risk awareness by shift and management personnel, actions to reduce the duration of the condition, actions to minimize the magnitude of risk increases (establishment of backup success paths or compensatory measures), and determination that the proposed OPERATIONAL CONDITION change is acceptable.

Consideration should also be given to the probability of completing restoration such that the requirements of the Limiting Condition for Operation would be met prior to the expiration of the ACTION requirement's specified time interval that would require exiting the Applicability.

Specification 3.0.4.b may be used with single, or multiple systems and components unavailable. NUMARC 93-01 provides guidance relative to consideration of simultaneous unavailability of multiple systems and components. (

The results of the risk assessment shall be considered in determining the acceptability of entering the OPERATIONAL CONDITION or other specified condition in the Applicability, and any corresponding risk management actions. The Specification 3.0.4.b risk assessments do not have to be documented.

The Technical Specifications allow continued operation with equipment unavailable in OPERATIONAL CONDITION 1 for the duration of the specified time interval. Since this is allowable, and since in general the risk impact in that particular OPERATIONAL CONDITION bounds the risk of transitioning into and through the applicable OPERATIONAL CONDITIONS or other specified conditions in the Applicability of the Limiting Condition for Operation, the use of the Specification 3.0.4.b allowance should be generally acceptable, as long as the risk is assessed and managed as stated above. However, there is a small subset of systems and components that have been determined to be more important to risk and use of the Specification 3.0.4.b allowance is prohibited. The Limiting Condition for Operations governing these system and components contain Notes prohibiting the use of Specification 3.0.4.b by stating that Specification 3.0.4.b is not applicable.

Specification 3.0.4.c allows entry into a OPERATIONAL CONDITION or other specified condition in the Applicability with the Limiting Condition for Operation not met based on a Note in the Specification which states Specification 3.0.4.c is applicable. These specific allowances permit entry into OPERATIONAL CONDITIONS or other specified conditions in the Applicability when the associated ACTION requirements to be entered do not provide for continued operation for an unlimited period of time and a risk assessment has not been performed. This allowance may apply to all the ACTION requirements or to a specific ACTION requirement of a Specification. The risk assessments l_

LIMERICK - UNIT 2 B 3/4 0-3a Amendment No. ir-4, 1:3r, Associated with Amendment No. 189

APPLICABILITY B SES performed to justify the use of Specifica tion 3.0.4.b usually only consider syste~s and components. For this reason, Specificat ion 3.0.4.c is typically applied to Specifica tions which describe values and parameters (e.g., Reactor Coolant Specific Activity) , and may be applied to other Specifica tions based on NRC plant-spe cific approval.

The provision s of this Specificat ion should not be interprete d as endorsing the failure to exercise the good practice of restoring systems or components to OPERABLE status before entering an associated OPERATIONAL CONDITION or other specified condition in the Applicabi lity.

The provisions of Specificat ion 3.0.4 shall not prevent changes in OPERATIONAL CONDITIONS or other specified conditions in the Applicabi lity that are required to comply with ACTION requirements. In addition, the provisions of Specifica tion 3.0.4 shall not prevent changes in OPERATIONAL CONDITIONS or other specified condition s in the Applicabi lity that result from any unit shutdown.

In this LIMERICK - UNIT 2 B 3/4 0-3al Amendment No. 1:r4, 1:3-r, Associated with Amendment No. 189 I

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3/4.0 APPLICABILI1Y BASES context, a unit shutdown is defined as a change in OPERATIONAL CONDITION or other specifie d conditio n fo the Applica bility associat ed with transitio ning from OPERATIONAL CONDITION 1 to OPERATIONAL CONDITION 2, OPERATIONAL CONDITION 2 to OPERATIONAL CONDITION 3, and OPERATIONAL CONDITION 3 to OPERATIONAL CONDITION 4.

Upon entry into an OPERATIONAL CONDITION or other specifie d condition in the Applica bility with the Limiting Condition for Operation not met, Specific ation

3. O. *1 and Speci fi cation 3. O. 2 require entry into the app 1i cab1e Condi ti ans and ACTION requirements until the Condition is resolved; until the Limiting Condition for Qperation is met, or until the unit is not within the Applica bility of the Technical Specific ation.

Surveill ances do not have to be performed on the associat ed inoperab le equipment (or on variable s outside the specified limits), as permitted by Specific ation 4.0.1. Therefor e, utilizin g Specific ation 3.0.4 is not a violatio n of Specific ation 4.0.1 or Specific ation 4.0.4 for any Surveill ances that have not been performed on inoperab le equipment. However, SRs must be met to ensure OPERABILITY prior to declarin g the associate d equipment OPERABLE (or variable within limits) and restorin g compliance with the affected Limiting Condition for Operation.

Specific ation 3.0.S establis hes the allowance for restorin g equipment to service under admfoi.strative controls when it has been removed from service or declared inoperab le to comply with ACTIONs. The sole purpose of this Specific ation is to provide an exception to Specific ations 3.0.1 and 3.0.2 (e.g., to not comply with the applicab le ACTION(s)) to allow the performance of required testing to demonstrate:

a. The OPERABILlTY of the equipment being returned to service, or

b. The OPERABILITY of other equipment.

The adminis trative controls ensure the time the equipment is returned to service in conflict with the requirements of the ACTIONs is limited to the time necessary to perform the required testing to demonstrate OPERABILITY. This Specific ation does not provide time to perform any other preventi ve or correcti ve maintenance. LCO 3.0.S should not be used in lieu of other practica ble alternat ives that comply with Required Actions and that do not require changing the MODE or other specifie d conditio ns in the Applica bility in order to demonstrate equipment is OPERABLE .. LCO 3.0.S is not intended to be used repeated ly.

An example of demonstrating equipment is OPERABLE with the Required Actions not met is opening a manual valve that was closed to comply with Required Actions to isolate a flowpath with excessive Reactor Coolant System (RCS) Pressure Isolatio n Valve (PIV) leakage in order to perform testing to demonstrate that RCS PIV leakage is now within limit.

...... I LIMERICK - UNIT 2 B 3/4 0-3b Amendment No. -3:z-4, r, Associa ted with Amendment No. 189

3/4.0 APPLICABILITY Examples of demonstrating equipment OPERABILITY include instances in which it is

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necessary to take an inoperable channel or trip system out of a tripped condition that was directed by a ReqLJired Action, if there is no Required Action Note for this purpose. An example of verifying OPERABILITY of equipment removed from service is taking a tripped channel out of the tripped condition to permit the logic to function and indicate the appropriate response during performance of required testing on the inoperable channel.

Examples of demonstrating the OPERABILITY of other equipment are taking an inoperable channel or trip system out of the tripped condition to 1) prevent the trip function from occurring during the performance of required testing on another channel in the other trip system, or 2) to permit the logic to function and indicate the appropriate response during the performance of required testing on another channel in the same trip system.

The administrative controls in LCO 3.0.5 apply in all cases to systems or components in Chapter 3 of the Technical Specifications, as long as the testing could not be conducted'while complying with the Required Actions. This includes the realignment or repositioning of redundant or alternate equipment or trains

• previously manipulated to comply with AffiONS, as well as equipment removed from service or declared inoperable to comply with AffiONS.

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L LIMERICK - UNIT 2 B 3/4 0-3bl Amendment No. i:r4, -3::3-r, Associated with Amendment No. 189

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3/4.0 APPLICABILITY Specification 3.0.6 establishes an exception to Specifications 3.0.1 and 3.0.2 for (

supported systems that have a support system Limiting Condition for Operation specified in the Technical Specifications (TS). The exception to Specification 3.0.1 is provided because Specification 3.0.1 would require that the ACTIONs of the associated inoperable supported system Limiting Condition for Operation be entered solely due to the inoperability of the support system. This exception is justified because the actions that are required to ensure the plant is maintained in a safe condition are specified in the support system Limiting Condition for Operation's ACTIONs. These ACTIONs may include entering the supported system's ACTIONS or may specify other ACTIONs. The exception to Specification 3.0.2 is provided because Specification 3.0.2 would consider not entering into the ACTIONs for the supported system within the specified time intervals as a TS noncompliance.

When a support system is inoperable and there is a Limiting Condition for Operation specified for it in the TS, the supported system(s) are required to be declared inoperable if determined to be inoperable as a result of the support system inoperability. However, it is not necessary to enter into the supported systems' ACTIONs unless directed to do so by the support system's ACTIONS. The potential confusion and inconsistency of requirements related to the entry into multiple support and supported systems' Limiting Condition for Operations' 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 ACTIONs.

However, there are instances where a support system's ACTION may either direct a supported system to be declared inoperable or direct entry into ACTIONS for the supported system. This may occur invnediately or after some specified delay to perform some other ACTION. Regardless of whether it is invnediate or after some (

delay, when a support system's ACTION directs a supported system to be declared inoperable or directs entry into ACTIONs *for a supported system, the applicable ACTIONs shall be entered in accordance with Specification 3.0.1.

Specification 6.17, "Safety Function Determination Program (SFDP)," ensures loss of safety function is detected and appropriate actions are taken. Upon entry into Specification 3.0.6, 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 ACTIONs.

The SFDP implements the requirements of Specification 3.0.6.

The following examples use Figure B 3.0-1 to illustrate loss of safety function conditions that may result when a TS support system is inoperable. In this figure, the fifteen systems that comprise Train A are independent and redundant to the fifteen systems .that comprise Train B. To correctly use the figure to illustrate the SFDP provisions for a cross train check, the figure establishes a relationship between support and supported systems as follows: the figure shows System 1 as a support system for System 2 and System 3; System 2 as a support system for System 4 and System 5; and System 4 as a support system for System 8 and System 9. Specifically, a loss of safety function may exist when a support system is inoperable and:

• a. A system redundant to system(s) supported by the inoperable support system is also inoperable (EXAMPLE B 3.0.6-1),

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LIMERICK - UNIT 2 B 3/4 0-3c Associated with Amendment No. 181

3/4.0 AP~LICABILITY BAS Es*:

~ .

y b. A system redundant-to system(s*) *;n turn supported'.by- tH*e,inopera*ble-

.supported.system_ is *a.lsoinoperable (EXAMPLE*B-3.0.6~2), or.

c.

• A system' redundant *to. support, system(*s )*_for the** suppor_ted. systems ..

(a) *and (b). above i~ .also. jno'pe,rable: ~EX_AMpLE B 3.:Q.6:.3)-;

For th~ foll owi rig: e*xampl.~~; refer :tQ Fi gur~' ff* 3. D:~li .:

• E-XAMP LE B- 3'. a:*. 6 , - l ...

If syste.in

• 2°.* of* Train* A, is i noperab 1$*.*and . . System 5' of: Tra iii. s: is. i noperabT e ,::

a* 1oss. of safety function** exists' .in. Systems::*5~*.. 10; a:n~ *lL*

• EXAMPLE B~j.0:6~~

I_f System 2 of.Train-A is inbperable,"and'.Systemll of-Train Bis iri6perab.*le; a loss of safe~y furi.ction ex.ists in.* System 11.

• EXAMPLE B* 3.0.6~3:

. If*System 2 of Train.A is irioperable,anct.:systemLof.Train B-i~' inoperable, ..

a *l OS S-~of *safety* fun.cti o:n .exists in. :systems 2 ,: 4,: 5;,. S*,: 9 ;i 10. and lL '.'.

IBAlli..8.** TRAIN B*;

System 4 *.

• 1~ys. te****m 8.

System 9.

• System z*. Syslem*Z .. **

I.

• s.yst~m1~:-*

• Sy.-stem. 1.0

• system 5:.:

I  :., ...

• ~y~;e~ ~1 *. *

• • System 1,**

System 5**.

• System,11 System 1

'<*~ *

• 1"'"m '2 systems***

• ** I-.Sy.. sta. m 1.2**

• System 13 System 13 System 3 System 7 I,,,_,, System 3

• System 7.* * .

Syst_em 14. *

• System 15.

• I System 15 Figure B 3.0-1 Configuration of Trains and systems*

If an evaluation determines that a loss of safety *function exists, the-appropriate ACTIONs of the Limiting Condition for Operation in which the loss of safety function exists are required to be entered: This loss of safety function does not require the* assumpti6n of additional. single failures or*1oss of off.site power. Since operations are being restricted in accordance-with the ACTIONs of the support system, any resulting temporary loss of redundancy or single failure protection is taken into account.

LIMERICK - UNIT 2 B 3/4 0-3d Associated with Amendment No. 181 I

3/4.0 APPLICABILITY When loss of safety function is determined to exist, and the SFDP requires entry (

into the appropriate ACTIONs of the Limiting Condition for Operation in which the loss of safety function exists, consideration must be given to the specific type of function affected. Where a loss of function is solely due to a single Technical Specification support system (e.g., loss of automatic start due to inoperable instrumentation, or loss of pump suction source due to low tank level),

the appropriate Limiting Condition for Operation is the Limiting Condition for Operation for the support system. The ACTIONs for a support system Limiting Condition for Operation adequately address the inoperabilities of that system without reliance on entering its supported system Limiting Condition for Operation. When the loss of function is the result of multiple support systems, the appropriate Limiting Condition for Operation is the Limiting Condition for Operation for the supported system.

Specification 4.0.1 through 4.0.5 establish the general requirements applicable to Surveillance Requirements. SR 4.0.2 and SR 4.0.3 apply in Section 6, Administrative Controls, only when invoked by a Section 6 Specification. These requirements are based on the Surveillance Requirements stated in the Code of Federal Regulations 10 CFR 50.36(c)(3):

"Surveillance requirements are requirements relating to test, calibration, or inspection to ensure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions of operation will be met."

Specification 4.0.1 establishes the requirement that SRs must be met during the OPERATIONAL CONDITIONS or other specified conditions in the Applicability for which the requirements of the Limiting Condition for Operation apply, unless otherwise specified in the individual SRs. This Specification is to ensure that (

Surveillances are performed to verify the OPERABILITY of systems and components, and that variables are within specified limits. Failure to meet a Surveillance within the specified Surveillance time interval and allowed extension, in accordance with Specification 4.0.2, constitutes a failure to meet the Limiting Condition for Operation.

Systems and components are assumed to be OPERABLE when the associated SRs have been met. Nothing in this Specification, however, is to be construed as implying that systems or components are OPERABLE when:

a. The systems or components are known to be inoperable, although still meeting the SRs; or

b. The requirements of the Surveillance(s) are known to be not met between required Surveillance performances.

Surveillances do not have to be performed when the unit is in an OPERATIONAL CONDITION or other specified condition for which the requirements of the associated Limiting Condition for Operation are not applicable, unless otherwise specified. The SRs associated with a Special Test Exception Limiting Condition for Operation are only applicable when the Special Test Exception Limiting Condition for Operation is used as an allowable exception to the requirements of a Specification.

LIMERICK - UNIT 2 B 3/4 0-3e Amendment No. ~.1:3-2, Associated with Amendment No. x83:, 188

APPLICABILilY B SES Unplanned events may satisfy the requirements (including applicable acceptance criteria) for a given SR. In this case, the unplanned event may be credited as fulfilling the performance of the SR. This allowance includes those SRs whose performance is normally precluded in a given OPERATIONAL CONDITION or other specified condition.

Surveillances, including Surveillances invoked by ACTION requirements, do not have to be performed on inoperable equipment because the ACTIONS define the remedial measures thai apply. Surveillances have to be met and performed in accordance with Specification 4.0.2, prior to returning equipment to OPERABLE status.

Upon completion of maintenance, appropriate post maintenance testing is required to declare equipment OPERABLE. This includes ensuring applicable Surveillances are not failed and their most recent performance is in accordance with

• Specification 4.0.2. Post maintenance testing may not be possible in the current OPERATIONAL CONDITION or other specified conditions in the Applicability due to the necessary unit parameters not'having been established. In these situations, the equipment may be considered OPERABLE provided testing has been satisfactorily.c ompleted to the extent possible and the equipment is not otherwise believed to be incapable of performing its function. This will allow operation to proceed to an OPERATIONAL CONDITION or other specified condition where other necessary post maintenance tests can be-completed.

Some examples of this process are:

a. Control Rod Drive maintenance during refueling that requires scram testing at> 950 psj. However, if other appropriate testing is satisfactorily completed and the scram time testing of Specification 4.1.3.2 is satisfied, the control rod can be considered OPERABLE. This allows startup to proceed to reach 950 psi to perform other necessary testing.

b. High pressure coolant injection (HPCI) maintenance during shutdown that requires system functional tests at a specified pressure.

Provided other appropriate testing is satisfactorily completed, startup can proceed with HPCI considered OPERABLE. This allows operation to reach the specified pressure to complete the necessary post maintenance testing.

LIMERICK - UNIT 2 B 3/4 0-3f Amendment No. 3:24, r, Associated with Amendment No. 181

APPLICABILITY Specification 4.0.2 establishes the limit for which the specified time interval for Surveillance Requirements may be extended. It permits an allowable extension (*.,

of the normal surveillance interval to facilitate surveillance scheduling and consideration of plant operating conditions that may not be suitable for conducting the surveillance; e.g., transient conditions or other ongoing surveillance or maintenance activities. It also provides flexibility to accommodate the length of a fuel cycle for surveillances that are performed at each refueling outage and are specified with an 24-month surveillance interval.

It is not intended that this provision be used repeatedly as a convenience to extend the surveillance intervals beyond that specified for surveillances that are not performed during refueling outages. Likewise, it is not the intent that REFUELING INTERVAL surveillances be performed during power operation unless it is consistent with safe plant operation. The limitation of Specification 4.0.2 is based on engineering judgment and the recognition that the nost probable result of any particular surveillance being perfonned is the verification of confonnance with the Surveillance Requirements. TI,is provision is sufficient to ensure that the reliability ensured through surveillance activities is not significantly degraded beyond that obtained from the specified surveillance interval.

• Specification 4.0.3 establishes the flexibility to defer declaring affected equipment inoperable or an affected variable outside the specified limits when a Surveillance has not been performed within the specified Surveillance time interval and allowed extension. A delay period of up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or up to the limit of the specified Surveillance time interval, whichever is greater, applies from the point in time that it is discovered that the Surveillance has not been performed in accordance with Specification 4.0.2, and not at the time that the specified Surveillance time interval and allowed extension was not met.

When a Section 6.8, "Procedures and Programs," specification states that the (

provisions of SR 4.0.3 are applicable, it permits the flexibility to defer declaring the testing requirement not met in accordance with SR 4.0.3 when the testing has not been completed within the testing interval (including the allowance of SR 4.0.2 if invoked by the Section 6.8 specification).

This delay period provides adequate time to perform Surveillances that have been missed. This delay period permits the performance of a Surveillance before complying with ACTION requirements or other remedial measures that might preclude performance of the Surveillance.

The basis for this delay period includes consideration of unit conditions, adequate planning, availability of personnel, the time required to perform the Surveillance, the safety significance of the delay in completing the required Surveillance, and the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the requirements. When a Surveillance with a Surveillance time interval based not on time intervals, but upon specified unit conditions, operating situations, or requirements of regulations (e.g., prior to entering OPERATIONAL CONDITION 1 after each fuel loading, or in accordance with 10 CFR 50, Appendix J, as modified by approved exemptions, etc.) is discovered to have not been performed when specified, Specification 4.0.3 allows for the full delay period of up to the specified Surveillance time interval to perform the Surveillance. However, since there is not a time interval specified, the missed Surveillance should be performed at the first reasonable opportunity.

Specification 4.0.3 provides a time limit for, and allowances for the performance of, Surveillances that become applicable as a consequence of OPERATIONAL CONDITION changes imposed by ACTION requirements. L.

LIMERICK - UNIT 2 B 3/4 0-4 Amendment No. 5, 3-4, -ir,1, 1 Associated with Amendment No. 189

3/4.0 APPLICABILITY BASES Specification 4.0.3 (Continued)

SR 4.0.3 is only applicable if there is a reasonable expectation the associated equipment is OPERABLE or that variables are within limits, and it is expected that the Surveillance will be met when performed. Many factors should be considered, such as the period of time since the Surveillance was last performed, or whether the Surveillance, or a portion thereof, has ever been performed, and any other indications, tests, or activities that might support the expectation that the Surveillance will be met when performed. An example of the use of SR 4.0.3 would be a relay contact that was not tested as required in accordance with a particular SR, but previous successful performances of the SR included the relay contact; the adjacent, physically connected relay contacts were tested during the SR performance; the subject relay contact has been tested by another SR; or historical operation of the subject relay contact has been successful. It is not sufficient to infer the behavior of the associated equipment from the performance of similar equipment. The rigor of determining whether there is a reasonable expectation a Surveillance will be met when performed should increase based on the length of time since the last performance of the Surveillance. If the Surveillance has been performed recently, a review of the Surveillance history and equipment performance may be sufficient to support a reasonable expectation that the Surveillance will be met when performed. For Surveillances that have not been performed for a long period or that have never been performed, a rigorous evaluation based.on objective evidence should provide a high degree of confidence that the equipment is OPERABLE. The evaluation should be documented in sufficient detail to allow a knowledgeable individual to understand the basis for the determination.

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"-' Failure to comply with*specified Surveillance time intervals and allowed extensions for SRs is expected to be an infrequent occurrence. Use of the delay period established by Specification 4.0.3 is a flexibility which is not intended to be used repeatedly to extend Surveillance intervals.

LIMERICK - UNIT 2 B 3/4 0-4a Associated with Amendment No. -3:88, 189

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APPLICABILITY

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Specification 4.0.2 establishes the limit for which the specified time interval for Surveillance Requirements may be extended. It permits an allowable extension of the normal surveillance interval to facilitate surveillance scheduling and consideration of plant operating conditions that may not be suitable for conducting the surveillance; e.g., transient conditions or other ongoing surveillance or maintenance activities. It also provides flexibility.to accommodate the length of a fuel cycle for surveillances that are performed at each refueling outage and are specified with an 24-month surveillance interval.

It is not intended that this provision be used repeatedly as a convenience to extend the surveillance intervals beyond that specified for surveillances that are not performed during refueling outages. Likewise, it is not the intent that REFUELING INTERVAL surveillances be performed during power operation unless it is consistent with safe plant operation. The limitation of Specification 4.0.2 is based on engineering judgment and the recognition that the most probable result of any particular surveillance being performed is the verification of conformance with the Surveillance Requirements. This provision is sufficient to ensure that the reliability ensured through surveillance activities is not significantly degraded beyond that obtained from the specified surveillance interval.

Specification 4.0.3 establishes the flexibility to defer declaring affected equipment inoperable or an affected variable outside the specified limits when a Surveillance has not been completed within the specified Surveillance time interval and allowed extension. A delay period of up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or up to the limit of the specified Surveillance time interval, whichever is greater, applies from the point in time that it is discovered that the Surveillance has not been performed in accordance with Specification 4.0.2, and not at the time that the specified Surveillance time interval and allowed extension was not met.

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This delay period provides adequate time to complete Surveillances that have been missed. This delay period permits the completion of a Surveillance before complying with ACTION requirements or other remedial measures that might preclude completion of the Surveillance.

The basis for this delay period includes consideration of unit conditions, adequate planning, availability of personnel, the time required to perform the Surveillance, the safety significance of the delay in completing the required Surveillance, and the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the requirements. When a Surveillance with a Surveillance time interval based not on time intervals, but upon specified unit conditions, operating situations, or requirements of regulations (e.g., prior to entering OPERATIONAL CONDITION 1 after each fuel loading, or in accordance with 10 CFR 50, Appendix J, as modified by approved exemptions, etc.) is discovered to have not been performed when specified, Specification 4.0.3 allows for the full delay period of up to the specified Surveillance time interval to perform the Surveillance. However, since there is not a time interval specified, the missed Surveillance should be performed at the first reasonable opportunity.

Specification 4.0.3 provides a time limit for, and allowances for the performance of, Surveillances that become applicable as a consequence of OPERATIONAL CONDITION changes imposed by ACTION requirements.

Failure to comply with specified Surveillance time intervals and allowed extensions for SRs is expected to be an infrequent occurrence. Use of the delay period established by Specification 4.0.3 is a flexibility which is not intended to be used as an operational convenience to extend Surveillance intervals. L LIMERICK - UNIT 2 B 3/4 0-4 Amendment No. i, 34, 124

APP LI CABI LITV While up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or the*limit of the specified Surveillance time interval is provided tb perform the miss~d Surveillance, it is expected that the missed Surveillance will be *performed at the-first reasonable opportunity. The determination of the.first reasonable opportunity-should* include consideration of the .impact* on plan_t risk*_(froril delaying . .the Si.arvei.llance* as* well as any p*lant configuration changes required or:~hutting~the~plan~ down th*perfor~ the- * ..

Su rv ei ll ance l* and* imp.act oil' any: ana:l ys is: assi.ampt.i ons*,. in** addi t.ion* to* unit..

con di ti'ons,, planning-, .. avai hbil'ity *of. personnel,. *and .the, ti me required to*

perform the** Surveillance:... This: risk impact: .should: be *manag!:!d through*. the .

program* in* pl ace -to imp l eml:!ilt. 10* CFR' 50'~ 65 (a H4r* and its' i mpl ementati on** .

guidance, NRC. Regul~tory,Guide 1.182,. 'As~essing and Managjhg Ri~k Bef~re:

Mainteriance. Activitt~s,at Nuclear Powe~ Plants~* This*Regulatory Guide-addresses consi~eration of* temporary and aggregate risk impacts, determination of risk managem~nt action thresh~l~s. and risk man~gement*action up to and including plant shutdown *. The:missed Sorveillance*should*be* treated~as. an emergent condition as discuss.ed. fn the Regulatory- Guide. The- risk ev.aluation may.use quantitative, qualititive~ o~*blended methods~ Th~ d~g~ee*of depth and rigor of the. evaluation should* be. commensurate: with*.th*e.impor.tance of the

• component.- . Missed*. SurveHTances for*,*important components :should* be:*analyzed

• quantitatively. If the.results.of the risk*evaluation determine _th~* r.isk increase:is*.significant,-this *evaluation should-be used*to determine the-*safest course of action .. All missed Surveillances*.will be* placed. in the Corrective Action Program~

If a Surveillanci~is not .completed-within the allowed del*ay period, then the.

equi pment:j s; considered inoperable or the: variable i's consi der.ed outsj de the*.

.:~J specified limits ~~d the ACTION requirements for-the applicable Ltmiting . *

'. __/ Condition for Operation begin immediately upon *expiration of* the delay period.

If a SLirvei1lance is failed within.the,del*ay.period or the variable is outside.

the specifi~d 1imits, then the equipment. is inop~rable*and.the Completion Times of the Required Actio_ns for *the appl ic*able LCO Conditions begi-n immediately upon. the failure-of* the .Surveillance.

Completion of the Surveillance within the delay period allowed by this.

Specification, or ~ithin the allowed times specified in th~ ACTION requirements, restores compli*ance with Specification 4.0.1.

• Specification 4.0.4 establishes the requirement that all applicable SRs ~ust be met before entry into an OPERATIONAL CONDITION or other* specified cond.;tion in the Applicability.

This Specification-ensures that system and component OPERABILITY requirements and variable limits.are met before entry into OPERATIONAL CONDITIONS or other specified conditions in the Applicability for which.these systems and components ensure safe operation of the unit. The provisions of this Specification should not be interpreted as endorsing the failure to exercise-the good practice of restoring systems or components to OPERABLE status before entering an associated OPERATIONAL CONDITION or other specified condition in the Applicability.

A provision is included to allow entry into an OPERATIONAL CONDITION or other specified condition in the Applicability when a limiting Condition for Operation is not met due to a Surveillance not being met in accordance with Specification 3.0.4.

.....,...j_ However, in certain circumstances, failing to meet an SR will not result in

• ---"' Specific_ation 4.0.4 r.estricting an OPERATIONAL CONDITION change or other specified LIMERICK - UNIT 2 8 3/4 0-5 Amendment No.~- .g.g._ +:24_ 1~?

APPLICABILIJY_

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condition change. When a system, subsystem, division, component, device, or variable is inoperable or outside its specified limits, the assqciated SR(s) are not required to be performed, per Specification 4.0.1, which states that surveillances do not have to be performed on inoperable equipment. When equipment is inoperable, Specification 4.0.4 does not apply to the associated SR(s) since the requirement for the SR(s) to be performed is removed. Therefore, failing to perform the Surveillance(s) within the specified Surveillance time interval does not-result in a Specification 4.0.4 restriction to changing OPERATIONAL CONDITIONS or other specified conditions of the Applicability. However, since the Limiting Condition for Operation is not met in this instance, Specification 3.0.4 will govern any restrictions that may (or may not) apply to OPERATIONAL CONDITION or other specified condition changes. Specification 4.0.4 does not restrict changing OPERATIONAL CONDITIONS or other specified conditions of the Applicability when a Surveillance has not been performed within the specified Surveillance time interval, provided the requirement to declare the Limiting Condition for Operation not met has been delayed in accordance with Specification 4.0.3.

The provisions of Specification 4.0.4 shall not prevent entry into OPERATIONAL CONDITIONS or other specified conditions in the Applicability that are required to comply with ACTION requirements. In addition, the provisions of Specification 4.0.4 shall not prevent changes in OPERATIONAL CONDITIONS or other specified conditions in the Applicability that result from any unit shutdown. In this context, a unit shutdown is defined as a change in OPERATIONAL CONDITION or other specified condition in the Applicability associated with transitioning from OPERATIONAL CONDITION 1 to OPERATIONAL CONDITION 2, OPERATIONAL CONDITION 2 to OPERATIONAL CONDITION 3, and OPERATIONAL CONDITION 3 to OPERATIONAL CONDITION 4.

• specification 4.0.5 establishes the requirement that inservice inspecti*on of ASME

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Code Class 1, 2 and 3 components and inservice testin~ of ASME Code Class 1, 2 and 3 pumps and valves shall be performed in accordance with a periodically updated version of Section XI of the ASME Boiler and Pressure Vessel Code and Addenda, and the ASME Code for Operation and Maintenance of Nuclear Power Plants (ASME OM Code) and applicable Addenda as required by 10 CFR 50.SSa. The provisions of SR 4.0.2 and SR 4.0.3 do not apply to the INSERVICE TESTING PROGRAM unless there is a specific SR referencing usage of the program ..

LIMERICK - UNIT 2 B 3/4 0-6 Amendment No. -3:3-r, 1:3-3, ~

Associated with Amendment No. 188

3/4.1 REACTIVITY CONTROL SYSTEMS l

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3/4.1.1 SHUTDOWN MARGIN A sufficient SHUTDOWN MARGIN ensures that (1) the reactor can be made subcritical from all operating conditions, (2) the reactivity transients associated with postulated accident conditions are controllable within acceptable limits, and (3) the reactor will be maintained sufficiently subcritical to preclude inadvertent criticality in the shutdown condition.

Since core reactivity values will vary through 'core life as a function of fuel depletion and poison burnup, the demonstration of SHUTDOWN MARGIN will be performed in the cold, xenon-free condition and shall show the core to be subcritical by at least R + 0.38% A k/k or R + 0.28% A k/k, as appropriate.

The 0.38% A*k/k includes uncertainties and calculation biases. The value of R in units of% A k/k is the difference between the calculated value of minimum shutdown margin during the operating cycle and the calculated shutdown margin at the time of the shutdown margin test at the beginning of cycle. The value of R must be positive or zero and must be determined for each fuel loading cycle.

Two different values are supplied in the Limiting Condition for Operation to provide for the different methods of demonstration of the SHUTDOWN MARGIN.

The highest worth rod may be determined analytically or by test. The SHUTDOWN MARGIN is demonstrated by (an insequence) control rod withdrawal at the beginning.of life fuel cycle conditions, and, if necessary, at any future time in the cycle if the first demonstration indicates that the required margin could be reduced as a function of exposure. Observation of subcriticality in this condition assures subcriticality with the most reactive control rod fully withdrawn.

Thjs reactivity characteristic has been a basic assumption in the analysis of plant performance and can be best demonstrated at the time of fuel loading, but the _margin must also be determined anytime a control rod is incapable of, insertion.

3/4.1.2 REACTIVITY ANOMALIES Since the SHUTDOWN MARGIN requirement for the reactor is small, a careful check on actual conditions to the predicted conditions is necessary, and the changes in reactivity can be inferred from these comparisons of core keffective Ckeff). Since the comparisons are easily done, frequent checks are not an imposition on normal operation5. A 1% ~hange is larger than is expected for normal operation so a change of this magnitude should be thoroughly evaluated.

A change as large as 1% would not exceed the design conditions of the reactor and is on the safe side of the postulated transients.

LIMERICK - UNIT 2 B 3/4 1-1 Associated with Amendment No. 168

REACTIVITY CONTROL SYSTEMS 3/4.1.3 CONTROL RODS The specif1cation of this section ensure that (1) the minimum SHUTDOWN MARGIN is mainta1ned, (2) the control rod insertion times are consistent with those used in the accident analysis, and (3) the potential effects of the rod drop accident are limited. The ACTION statements permit variations from the basic requirements but at the same time impose more restrictive criteria for continued operation. A limitation on inoperable rods is set such that the resultant effect on total rod worth and scram shape will be kept to a minimum. The requirements for the various scram time measurements ensure that any indication of systematic problems with rod drives will be investigated on~ timely basis.

Damage within the control rod drive mechanism could be a generic problem, therefore with a control rod immovable because of excessive friction or mechanical interference, operation of the reactor is limited to a time period which is reasonable to determine the cause of the inoperability and at the same time prevent operation with a large number of inoperable control rods.

Control rods that are inoperable for other reasons are permitted to be taken out of service provided that those in the nonfully-inserted position are consistent with the SHUTDOWN MARGIN requirements.

The number of control rods permitted to be inoperable could be more than the eight allowed by the specification, but th~ occurrence of eight inoperable rods could be indicative of a generic problem and the reactor must be shutdown for investigation and resolution of the problem.

The control rod system is designed to bring the reactor subcritical at a

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rate fast enough to prevent the MCPR from becoming less than the fuel cladding safety limit during the limiting power transient analyzed in Section 15.2 of the FSAR. This analysis shows that the negative reactivity rates resulting from the scram with the average response of all the drives as given in the specifications, provided the required protection and MCPR remains greater than the fuel cladding safety limit. The occurrence of scram times longer then those specified should be viewed as an indication of a systemic problem with the rod drives and therefore the surveillance interval is reduced in order to prevent operation of the reactor for long periods of time with a potentially serious problem.

Scram time testing at zero psig reactor coolant pressure is adequate to ensure that the control rod will perform its intended scram function during startup of the plant until scram time testing at 950 psig reactor coolant pressure is performed prior to exceeding 40% rated core thermal power.

The scram discharge volume is required to be OPERABLE so that it will be available when needed to accept discharge water from the control rods during a reactor scram and will isolate the reactor coolant system from the containment when required.

The OPERABILITY of all SDV vent and drain valves ensures that the SDV vent and drain valves will close during a scram to contain reactor water discharged to the SDV piping. The SDV has one common drain line and one common vent line.

Since the vent and drain lines are provided with two valves in series, the single

(....__ __..,-

LIMERICK - UNIT 2 B 3/4 1-2 Amendment No.~. 131

REACTIVITY CONTROL SYSTEMS BA CONTROL RODS (Continued) failure of one valve in the open position will not impair the isolatio n function of the system. Addition ally, the valves are required to open on scram reset to ensure that a path is availabl e for the SDV piping to drain freely at other times.

When one SDV vent or drain valve is inoperable in one or more lines, the valves must be restored to OPERABLE status within 7 days. The allowable outage time is reasonab le, given the level of redundancy in the lines and the low is probabi lity of a scram* occurring while the valve(s) are inoperab le. The SDV still isolable since the redundant valve in the affected line is OPERABLE. During these periods, the single failure criterio n may not be preserved, and a higher risk exists to allow reactor water out of the primary system during a scram.

If both* valves in a line are inoperable, the line must be isolated to contain the reactor coolant during a scram. When a line is isolated , the potentia l for an inadvert ent scram due to high SDV level is increase d.

ACTION "e" is modified by a note("** **") that allows periodic draining and venting of the SDV when a line is isolated . During these periods, the line may be unisolat ed under adminis trative control. This allows any accumulated water in the line to be drained, to preclude a reactor scram on SDV high level. This is acceptable since the adminis trative controls ensure the valve can be closed 8 quickly, by a dedicated operator , if a scram occurs with the valve open. The hour allowable outage time to isolate the line is based on the low probabi lity of a scram occurring while the line is not isolated and the unlikelih ood of signific ant CRD seal leakage.

Control rods with inoperable accumulators are declared inoperab le and Specific ation 3.1.3.1 then applies. This prevents a pattern of inoperab le accumulators that would result in less reactivi ty insertio n on a scram than has been analyzed even though control rods with inoperab le accumulators may still be inserted with normal drive water pressure . The drive water pressure normal operatin g range is specifie d in system operatin g procedures which provide ranges for system alignment and control rod motion (exercis ing). Operabi lity of the accumulator ensures that there is a means availabl e to insert the control rods even under the most unfavorable depressu rization of the reactor. A control rod is considered trippabl e if it is capable of fully insertin g as a result of a scram signal.

LIMERICK - UNIT 2 8 3/4 1-2a Amendment No. -GJ, -lJ-1, 140

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REACTIVITY CONTROL SYSTEMS.

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• 8~ A ~ ~ = = = = = = = = = = = = = = = = ~ = = ~ = = = = = = = = = = = =

CONTROL* RODS (Continued)*

Control rod coupling integrity is required to ~nsure compliance with the analysis of::the,--rdd<drop acddent in the* FSAR. The ov*ertravel positi.on feature prov1des .the. only positive means of deter~ining Jhat a roc;L is .. proper_ly_ c;oupled ..

. 'and thfrefore this *check. mu.st be performed. 'pdor td achieving criti c:aTi ty after completing CORE- ALTERATIONS that. could have-affected the_ control.: rod coupling integrity .. The subsequent check *is performed, as. a backup to the initfal

• demon--

s t r a t io h '.0 * * * * * * * * *

In ord'er. to e*nsure that ttie contr'ol *ro*d patter-~s can: be fol 1owe*d and* there~

fore that other parameters are within their limits, the control rod position indication system must b~ OPERABLE. *

• The .. contra] rod housing .support* restricts *the outward movement of a contra 1 rod to less than 3 fochesin the event of*a housing.failure. -Thei*amount of*.

rod reacti.vity which could: be. added by this sniall . aindunt of "r"od *withdrawal is* '.**...

les_s than. a normal withdrawal increment and wili. not.contribute.*fo,any damage .

to the. primary~ cool ant system; . The support is** not requ_ir;ed. when there *is.* no pressure to act* a~ ~ dr.iving force to rapidly' eject a'*dr:.ive houstng.:_ * .* .*:

The required surveillances are *adequafo,:to *determine that'th*e* rods a*re OPERABLE-.-* 1.

and not so,freq~en~_as*to cause*excessive, wear on*the~system.componen tsr

314,1.4 CONTROL ROD PROGRAM CONTROLS Cdrit~ol ro~withdrawal *and inse~tion sequences, are*established*to~assu re*

that the<maxiriluin :;nsequence-i-ndividual. cb'ntrol 'rod .. or'.confrol rod segments whi.ch '

are withdrawn at:-any time--during*the fuer*cycle could no't be**worth:enough to '*

result in a' peak* fuel. enthalpy greater than 280 cal/gm in the *evenLof *a ccintrol

• rod**drop accident. The__ ,specified sequences are characterized: by homogeneous; scattered-patterns of control. rod withdrawal. When THERMAL* POWER is greater-

"than 10% *of RATED THERMAL POWER, there is-*no possible rod *worth.-which, if *.

dropped at the d~sigh rate- of the velocity limiter;* could result in a peak enthalpy.. of 280 cal/gm.- Thus. requiri.rig the RWM to be. OPERABLE when, .

THERMAL POWER is 1ess than or equa 1 to 10% of RATED THERMAL POWER provides adequate. control.*

• Th~ RWM ~ro~ides* automatic supervision to assure that.~ut-oi-.

sequence rods wi n:.. not. be. withdrawn or*,inserted.'

The. analysis of the rod drop accident.is. presente.d in Section 15.4.9 of the FSAR and the techniques of the analysis are presented in a topical report, Reference 1, and two supplements, References 2 and 3. Additional pertinent*

analysis is also contained in Amendment 17 to the Reference 4 Topical Report.

The RBM is designed to automatically.prevent fuel damage in the event of erro~eou~ rod withdrawal from locati*ons of high*-power-density over the range of power operation. Two channels are provided. Tripping one of the channels will bl~ck erroneous rod withdrawal to ptevent fuel damage. This system backs up the written sequence used by the operator for withdrawa 1 of contra 1 rods. RBM OPERA-BI LITY is required when the limiting condition described in Specification 3.1.4.3 exists.

LIMERICK - UNIT 2 B 3/4 1-3 Amendment No. 4,g,147

REACTIVITY CONTROL SYSTEMS 3/4.1.5 STANDBY LIQUID CONTROL SYSTEM

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The standby liquid control system provides a backup capabili ty for bringing the reactor from full power to a cold, Xenon-free shutdown, assuming that the withdrawn control rods remain fixed in the rated power pattern. To meet this objectiv e it is necessary to inject a quantity of boron which produces a concen-tration of 660 ppm in the reactor core and other piping systems connected to the reactor vessel. To allow for potential leakage and improper mixing, this con-centratio n is increased by 25%. The required concentration is achieved by having availabl e a minimum quantity of 3,160 gallons of sodium pentaborate solution containng a minimum of 3,754 lbs of sodium pentaborate having the requisite 10 atom% enrichment of 29% as determined from Reference 5. This quantity ofBoron-solution is a net amount which is above the pump suction shutoff level setpoint thus allowing for the portion which cannot be injected .

The above quantitie s calculated at 29% Boron-10 enrichment have demonstrated by analysis to provide a Boron-10 weight equivalent of 185been the sodium pentaborate solution. Maintaining this Boron-10 weight in thelbsnetin tank contents ensures a sufficien t quantity of boron to bring the reactor to a cold, Xenon-free shutdown.

The pumping rate of 37.0 gpm provides a negative reactivit y insertion rate over the permissible solution volume range, which adequately compensates for the positive reactivit y effects due to elimination of steam voids, increased water density from hot to cold, reduced doppler effect in uranium, reduced neutron leakage ftom boiling to cold, decreased control rod worth as the moderato r cools, and xenon decay. The temperature requirement ensures that the sodium pentabor ate always remains in solution.

With redundant pumps and explosive injection valves and with a highly reliable control rod scram system, operation of the reactor is permitted to C.

continue for short periods of time with the system inoperable or for longer periods of time with one of the redundant components inoperable.

The SLCS system consists of three separate and independent pumps and explosive valves. Two of the separate and independent pumps and explosive valves are required to meet the minimum requirements of this technical specifica tion and, where applicab le, satisfy the single failure criterion . To ensure that SLCS pump discharge pressure does not exceed the SLCS relief valve setpoint during operation following an anticipat ed transien t without scram (ATWS) event, no more than two pumps shall be aligned for automatic operation in OPERATIONAL CONDITIONS l, 2, and

3. This maintains the equivalent control capacity to satisfy 10 CFR 50.62 (Requirements for reduction of risk from anticipa ted transien ts without scram (ATWS). With three pumps aligned for automatic operation, the system is inoperab le and ACTION statement (b) applies.

The SLCS must have an equivalent control capacity of 86 gpm of 13% weight sodium pentaborate in order to satisfy 10 CFR 50.62. As part of the program the ATWS analysis was updated to reflect the new rod line. AsARTS/MELLa result L

of this it was determined that the Boron 10 enrichment was required to be increased to 29% to prevent exceeding a suppression pool temperature of 190°F. This equivalency requirement is fulfilled by having a system which satisfie s the equation given in 4.1._5.b.2.

The upper limit concentration of 13.8% has been establish ed as a reasonable limit to prevent precipita tion of sodium pentaborate in the event of tank heating, which allow the solution to cool. A SLCS Pump flowrate aofloss of (minimum) and a Sodium Pentaborate Solution concentration of 9% by weight 37.0 gpm (minimum) will require a Boron-10 enrichment of 49 atom% to be The decreased pump flowrate and increased solution enrichment areadded to the tank.

acceptab because the results of the ATWS Rule Equation will remain> 1.0. le (

LIMERICK - UNIT 2 B 3/4 1-4 Amendment No. 48, ~.

Associated with Amendm ent~. 195

REACTIVITY CONTROL SYSTEMS BA STANDBY LIQUID CONTROL SYSTEM (Continued)

Surve illanc e requirements are est~bl ished on a frequencyboron that assures a high soluti on is establ ished , conce ntratio n reliab ility of the system. Once the a check on the.te mpera ture will not vary unless more boron or water is added, thususe.

and voJume assure s that the soluti on is availa ble for that these valves Replacement of the explos ive charges in the valves will assure '

wil 1 not fai 1 because of deteri oratio n of the charge s.

The Standby Liquid Control System also has a post-OBA LOCA safety functi on to bulk pH above 7.0. The buffer ing of buffer Suppression Pool pH in order to maintain lution to satisf y the Suppression Pool pH is necess ary to preven t iodine re-evo Term. Manual initia tion is used, and the minimum methodology for Altern ative Source is 256 1 bs. Given amount of total boron requir ed for Suppression Pool pH buffer ing the total boron in the that at least 185 lbs of Boron-10 is maintained in the tank, ments from 29% to 62%.

tank will be greate r than 256 lbs for the range of enrich ACTION Statement (a) applie s only to OPERATIONAL CONDITIONS 1 and 2 because a and the post-OB A LOCA single pump can satisf y both the reacto r control functi on ion is not requir ed until functi on to contro l Suppression Pool pH iince boron inject TIONAL CONDITIONS 1, 2 and 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> post-LOCA. ACTION Statement (b) applie s to OPERA 3 to address the post-LOCA safety function of the SLC system.

C. J. Paone, R. C. Stirn and J. A. Woolley, "Rod Drop Accide nt Analysis 1.

for Large BWR' s," G. E. Topical Report NED0-10527, March 1972.

10527, July

2. C. J. Paone, R. C. Stirn, and R. M. Young, Supplement 1 to NED0-1972.

Cores,"

3. J.M. Haun, C. J. Paone, and R. C. Stirn, Addendum 2, "Exposed Supplement 2 to NED0-10527, January 1973.

24011-P-A,

4. Amendment 17 to General Electr ic Licensing Topical Report NEDE-

"General Elect ric Standa rd Applic ation for Reacto r Fuel".

Analyses for

5. "Maximum Extended Load Line Limit and ARTS Improvement Program Revisi on 2, October Limerick Generating Statio n Units 1 and 2," NEDC- 32193P ,

1993.

B 3/4 1-5 Amendment No. 4@,-!4&,-14-+,

LIMERICK - UNIT 2 ECR 14-00055

.r-. I~

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3/4.2 POWER DISTRIBUTION LIMITS BASES 3/4.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE This specific ation assures that the peak cladding temperature (PCT) will not following the postulated design basis Loss-of-Coolant Accident (LOCA) analysis exceed the limits specified in 10 CFR 50.46 and that the fuel design limits specified in NEDE-24011-P-A (Reference 2) will not be exceeded.

Mechanical Design Analysis: NRC approved methods (specifi ed in

• Reference 2) are used to demonstrate that all fuel rods in a lattice operatin g at the bounding power history, meet the fuel design limits specifie d in Reference 2. No single fuel rod follows, or is capable of following, this for bounding power history. This bounding power history is used as the basis the fuel design analysis MAPLHGR limit.

LOCA Analysis: A LOCA analysis is performed in accordance with IOCFR50 Appendix K to demonstrate that the permissible planar power (MAPLHGR) limits d comply with the ECCS limits specified in 10 CFR 50.46. The analysis is performe tion for the most limiting break size, break location , and single failure combina for the plant, using the evaluation model described in Reference 9.

The MAPLHGR limit as shawm in the CORE OPERATING LIMITS REPORT is the most limiting composite of the fuel mechanical design anaylsis MAPLHGR and the ECCS MAPLHGR limit.

Only the most limiting MAPLHGR values are shown in the CORE OPERATING LIMITS REPORT for multiple lattice fuel. Compliance with the specific lattice MAPLHGR operating limits, which are-available in Reference 3, is ensured by use of the process computer.

As a result of no longer utilizin g an APRM trip setdown requirement, additional constra ints are placed on the MAPLHGR limits to assure adherence to the fuel-mechanical design bases. These constrain~s are introduced through the MAPFAC(P) and MAPFAC(F) factors as defined in the COLR.

JAN 3 1 1995 LIMERICK - UNIT 2 B 3/4 2-1 Amendment No.#, l#, 48

POWER DISTRIBUTION LIMITS BASES 3/4.2.2 lDELETEPl C INFORMATION CONTAINED ON THIS PAGE HAS BEEN DELETED

(

JAN 3 1 .1995 LIMERICK - UNIT 2 B 3/4 2-2 Amendment No.~' ?~, 48

)

f LEFT INTENTIONALLY BLANK LIMERICK - UNIT 2 B 3/4 2-3 Amendment No. 14 HAY O6 1991

POWER DISTRIBUTION LIMITS 3/4.2,3 MINIMUM CRITICAL POWER RATIO (

The required operating limit MCPRs at steady-state*op erating conditions as specified in Specification 3.2.3 are derived from the established fuel cladding integrity Safety Limit MCPR, and an analysis of abnormal operational transients. For any abnormal operating transient analysis evaluation with the initial condition of the reactor being at the steady-state operating limit, it is required* that less than 0.1% of fuel rods in the core are susceptible to transition boiling or that the resulting MCPR does not decrease below the Safety Limit MCPR at any time during the transient assuming instrument trip setting given in Specification 2.2.

To assure that the fuel cladding integrity Safety Limit is not exceeded during any anticipated abnormal operational transient, the most limiting tran-sients have been analyzed to determine which result in the largest reduction in CRITICAL POWER RATIO (CPR). The type of transients evaluated were loss of flow, increase 1n pressure and power, positive reactivity insertion, and coolant temperature decrease.

The evaluation of a given transient begins with the system initial para-meters shown in FSAR Table 15.0-2 that are input to a BWR system dynamic behavior transient computer program. The codes used to evaluate transients are discussed in Reference 2.

The MCPR operating limits derived from the transient analysis are dependent on the operating core flow and power state (MCPR(F), and MCPR(P), respectively) to (

ensure adherence to fuel design limits during the worst transient that occurs with moderate frequency (Ref. 6). Flow dependent MCPR limits (MCPR{F)) are determined by steady state thermal hydraulic methods with key physics response inputs benchmarked using the three dimensional BWR simulator code (Ref. 7) to analyze slow flow runout transients.

Power dependent MCPR limits (MCPR(P)) are determined by the codes used to evaluate transients as described in Reference 2. Due to the sensitivity of the transient response to initial core flow levels at power levels below those at which the turbine stop valve closure and turbine control valve fast closure scrams are bypassed, high and low flow MCPR(P), operating limits are provided for operating between 25% RTP and 30% RTP.

The MCPR operating limits specified in the COLR are the result of the Design Basis Accident (OBA) and transient analysis. The operating limit MCPR is determined by the larger of the MCPR(F), and MCPR(P) limits.

LIMERICK - UNIT 2 B 3/4 2-4 Amendment No. 4, 4S ECR L~ 99 QllJ8, ECR LG 12-00035

POWER DISTRIBUTION LIMITS BASES MINIMUM CRITICAL POWER RATIO (Continued)

At THERMAL POWER level s less than or equal to 25% pump of RATED THERMAL POWER, the react or will be operating at minimum recirc ulatio n speed and the moderator void content will be very small. For all designated contro l rod patte rns which may be employed at this point, operating plant experience indic ates that the resul ting derab le margi n. During initia l MCPR value is in excess of requirements by a consi will be made at 25% of RATED THERMAL startu p testin g of the plant , a MCPR evaluation The MCPR margin will thus be POWER level with minimum recirc ulatio n pump speed .

ation below this power level will be shown to demonstrated such that future MCPR evalu MCPR when THERMAL POWER is be unnecessary. The daily requirement for calcu lating suffic ient since power great er than or equal to 25% of RATED THERMAL POWER is been signi fican t power or distri butio n shift s are very slow when there have not control rod changes. The requirement for calcu lating MCPR when a limiti ng control rod patte rn is approached ensures that MCPR will be known following a change in place operation at THERMAL POWER or power shape, regardless of magnitude, that could a thermal limit .

3/4.2 .4 LINEAR HEAT GENERATION RATE This speci ficati on assures that the Linear Hj~t Gener ation Rate (LHGR) in any rod is less than the design linea r heat generation even if fuel pelle t densi ficati on is postu lated.

Reference:

I. Deleted.

-P-*

2. "General Elect ric Standard Application for Reactor Fuel," NEDE-24011 A (late st approved revis ion).

2,"*NEDC-

3. "Basis of MAPLHGR Technical Speci ficati ons for Limerick Unit 31930P (as amended).

4. Deleted

5. Increased Core Flow and Partia l Feedwater Heating Analy sis for Limerick Generating Station Unit 2 Cycle 1, NEDC-31578P, March 1989 including Errata and Addenda Sheet No. 1*dated May 31, 1989.

6. NEDC-32193P, "Maximum Extended Load Line Limit andUnits ARTS Improvement Program Analyses for Limerick Generating Statio n 1 and 2,"

Revision 2, October 1993.

7. NED0-30130-A, "Steady State Nuclear Methods," May 1985.

Model for

8. NED0-24154, "Qualification of the One-Dimensional Core Transient Boiling Water Reactors," October 1978.

-LOCA

9. NEDC-32170P, "Limerick Generating Statio n Units 1 and 2 SAFER/GESTR Loss-of-Coolant Accident Analysis," June 1993.

I

~

B 3/4 2-5 .Amendment No. ~' t#, 48 LIMERICK - UNIT 2 JAN 3 1 1995

(', ~

\

3/4.3 INSTRUMENTATION 3/4.3,1 REACTOR PROTECTION SYSTEM INSTRUMENTATION The reactor protection system automatically initiates a reactor scram to:

a. Preserve the integrity-~of the fuel cladding.

b. Preserve the integrity of the reactor coolant system.

• c. Minimize the energy which must be adsorbed following a loss-of-coolant accident, and

d. Prevent inadvertent criticality.

This specification provides the limiting conditions for operation necessary to preserve the ability of the system to perform its intended function even during periods when instrument channels may be out of service because of maintenance. When necessary, one channel may be made inoperable for brief intervals to conduct required surveill~nce.

• The reactor protection system is made up of two independent trip systems.

There are usually four channels to monitor each parameter with two channels in each trip system. The outputs of the channels in a trip system are combined in a logic so that either channel will trip that trip system. The tripping of both trip systems wi 11 produce a reactor scram. The APRM system is divided into four APRH channe 1s and four 2-0ut-Of-4 Voter channels. Each APRM channel provides inputs to each of the four voter channels. The four voter channels are divided into two groups of two each, with each group of two providing inputs to one RPS trip system. The system is

,.,,.,-#' designed to allow one APRM channel, but. no voter channels,* to be bypassed.

The system meets the intent of IEEE-279 for nuclear power plant protection systems *. Surveillance intervals are determined in accordance with the Surveillance Frequency Control Program and maintenance outage times have been determined in accordance with NEDC-30851P-A, "Technical Specification Improvement Analyses for BWR Reactor Protection System" and NEDC-32410P-A, "Nuclear Measurement Analysis and Control Power Range Neutron Monitor (NUMAC PRNM) Retrofit Plus Option III Stability Trip Function." The bases for the trip settings of the RPS are discussed in the bases for Specification 2.2.1.

The APRM Functions include five Functions accomplished by the four APRM channels (Functions 2.a, 2.b, 2.c, 2.d, and 2.f) and one accomplished by the four 2~

Out-Of-4 Voter channels (Function 2.e>. Two of the five Functions accomplished by the APRM channels are based on neutron flux only (Functions 2.a and 2.c), one

• Function is based on neutron flux and recirculation drive flow (Function 2.b) and one is based on equipment status (Function 2.d). The fifth Function accomplished by the APRM channels is the Oscillation Power Range Monitor COPRM) Upscale trip Function 2.f, which is based on detecting oscillatory characteristics in the neutron flux.

The OPRM Upscale Function is also dependent on average neutron flux (Simulated Thermal Power) and recirculation drive flow, which are used to automatically enable the output trip.

The Two-Out-Of-Four Logic Module includes 2-0ut-Of-4 Voter hardware and the APRM Interface hardware. The 2-0ut-Of-4 Voter Function 2.e votes APRM Functions 2.a, 2.b, 2.c, and 2.d independently of Function 2.f. This voting is accomplished by the 2-0ut-Of-4 Voter hardware in the Two-Out-Of-Four Logic Module. The voter includes separate outputs to RPS for the two independently voted sets of Functions, each of which is redundant (four total outputs). The analysis in Reference 2 took credit for this redundancy in the justification of the 12-hour allowed out.-of-service time for

3/4,3 INSTRUMENTATION 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION (continued) (

Action b, so the voter Function 2.e must be declared inoperable if any of its functionalit y is inoperable. The voter Function 2.e does not need to be declared inoperable due to any failure affecting only the APRM Interface hardware portion of the Two-Out-Of-Four Logic Module.

Three of the four APRM channels and all four of the voter channels are required to be OPERABLE to ensure that no single failure will preclude a scram on a valid signal. To provide adequate coverage of the entire core, consistent with the design bases for the APRM Functions 2.a, 2.b, and 2.c, at least 20 LPRM inputs, with at least three LPRM inputs from each of the four axial levels at which the LPRMs are located, must be operable for each APRM channel. In addition, no more than 9 LPRMs may be bypassed between APRM calibrations (weekly gain adjustments). For the OPRM Upscale Function 2.f, LPRMs are assigned to cells" of 3 or 4 detectors. A minimum of 23 cells (Reference 9), each with a minimum of 2 OPERABLE LPRMs, must be OPERABLE for each APRM channel for the OPRM Upscale Function 2.f to be OPERABLE in that channel. LPRM gain settings are determined from the local flux profiles measured by the TIP system. This establishes the relative local flux profile for appropriate representati ve input to the APRM System. The 2000 EFPH frequency is based on operating experience with LPRM sensitivity changes.

References 4, 5 and 6 describe three algorithms for detecting thermal-hydraulic instability related neutron flux oscillations : the period based detection algorithm, the amplitude based algorithm, and the growth rate algorithm. All three are implemented in the OPRM Upscale Function, but the safety analysis takes credit only for the period based detection algorithm. The remaining algorithms provide defense in depth and additional protection against unanticipated oscillations . OPRM Upscale Function OPERABILITY for Technical Specification purposes is based only on the period based detection algorithm.

An OPRM Upscale trip is issued from an APRM channel when the period based (

detection algorithm in that channel detects oscillatory changes in the neutron flux, -

indicated by the combined signals of the LPRM detectors in any cell, with period confirmations and relative cell amplitude exceeding specified setpoints. One or more cells in a channel exceeding the trip conditions will result in a channel trip.

OPRM Upscale trip is also issued from the channel if either the growth rate or An amplitude based algorithms detect growing oscillatory changes in the neutron flux for one or more cells in that channel. .

The OPRM Upscale Function is required to be OPERABLE when the plant is at

~ 25% RATED THERMAL POWER. The 25% RATED THERMAL POWER level is selected to provide margin in the unlikely event that a reactor power increase transient occurring while the plant is operating below 29.5% RATED THERMAL POWER causes a power increase to or beyond the 29.5% RATED THERMAL POWER OPRM Upscale trip auto-enable point without operator action. This OPERABILITY requirement assures that the OPRM Upscale trip automatic-enable function will be OPERABLE when required.

Actions a, band c define the Action(s) required when RPS channels are discovered to be inoperable. For those Actions, separate entry condition is allowed for each inoperable RPS channel. Separate entry means that the allowable time clock(s) for Actions a, b or c start upon discovery of inoperabilit y for that specific channel. Restoration of an inoperable RPS channel satisfies only the action statements for that particular channel. Action statement(s) for remaining inoperable channel Cs) must be met according to their original entry time.

A Note has been provided to modify the Actions when Functional Unit 2.b and 2.c channels are inoperable due to failure of SR 4.3.1.1 and gain adjustments are necessary. The Note allows entry into associated Actions to be delayed for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> if the APRM is indicating a lower power value than the calculated power Ci .e., the gain adjustment factor (GAF) is high (non-conser vative)). The GAF for any channel is defined as the power value determined by the heat balance divided by the APRM reading for that channel. Upon completion of the gain adjustment, or (

LIMERICK - UNIT 2 B 3/4 3-la Amendment No. -l-7,~,,9.J,+G-9-,.iJ.9.,-+/--9-9, Associated with Amendment~. 196

3/4.3 INSTRUMENTATION 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION (continued) expiration of the allowed time, the channel must be returned to OPERABLE status or the applicable Actions taken. This Note is based on the time required to perform gain adjustments on multiple channels.

Because of the diversity of sensors available to provide trip signals and the redundancy of the RPS design, an allowable out of service time of 12 .hours has been shown to be acceptable (NEDC-30851P-A and NEDC-32410P-A) to permit restoration of any inoperable channel to OPERABLE status. However, this out of service time is only acceptable provided that the associated Function's (identified as a "Functional Unit" in Table 3.3.1-1) inoperable channel is in one trip system and the Function still maintains RPS trip capability.

The requirements of Action a are intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same trip system for the same Function result in the Function not maintaining RPS trip capability. A Function is considered to be maintaining RPS trip capability when sufficient channels are OPERABLE or in trip (or the associated trip system is in trip), -such that both trip systems will genera(~ a trip signal from the given Function on a valid signal.

For the typical Function with one-out-of-two taken twice logic, including the !RM Functions and APRM Function 2.e (trip capability associated with APRM Functions 2.a, 2.b, 2.c, 2.d, and 2.f are discussed below), this would require both trip systems to have one channel OPERABLE or in trip (or the associated trip system in trip).

For Function 5 (Main Steam Isolation Valve--Closure), this would require both trip systems to have each channel associated with the MSIVs in three main steam lines (not necessarily the same main steam lines for both trip systems) OPERABLE or in trip (or the associated trip system in trip).

For Function 9 (Turbine Stop Valve-Closure), this would require both trip systems to have three channels, each OPERABLE or in trip (or the associated trip system in trip).

The completion time to satisfy the requirements of Action a is intended to allow the operator time to evaluate and repair any discovered inoperabilities. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.

With trip capability maintained, i.e., Action a satisfied, Actions band c as applicable must still be satisfied. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, Action b requires that the channel or the associated trip system must be placed in the tripped condition.

Placing the inoperable channel in trip (or the associated trip system*in trip) would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue.

As noted, placing the trip system in trip is not applicable to satisfy Action b for APRM Functions 2.a, 2.b, 2.c, 2.d, or 2.f. Inoperability of one required APRM channel affects both trip systems. For*that condition, the Action b requirements can only be satisfied by placing the inoperable ApRM_ channel in trip .. Best.orjng OPERABILITY or placing the inoperable APRM channel in trip are the only actions that will restore capability to accommodate a single APRM channel failure. Inoperability of more than one required APRM channel of the same trip function results in loss of trip capability and the requirement to satisfy Action a.

I "lll!lii'° LIMERICK - UNIT 2 B 3/4 3-lb Amendment No. -+/-09-, -+/-J.9.

Associated with Amendment 196

3/4.3 INSTRUMENTATION 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION (continued) (

The requirements of Action c must be satisfied when, for any one or more Functions, at least one required channel is inoperable in each trip system. In this condition, provided at least one channel per trip system is OPERABLE, normally the RPS still maintains trip capability for that Function, but cannot accommodate a single failure in either trip system (see additional bases discussion above related to loss of trip capability and the requirements of Action a, and special cases for Functions 2.a, 2.b, 2.c, 2.d, 2.f, 5 and 9).

The requirements of Action c limit the time the RPS scram logic, for any Function, would not accommodate single failure in both trip systems (e.g., one-out-of-one and one-out-of-one arrangement for a typical four channel Function). The reduced reliabilit y of this logic arrangement was not evaluated in NEDC-30851P-A for the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Completion Time. Within the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowance, the associated Function must have all required channels OPERABLE or in trip (or any combination) in one trip system.

Completing the actions required by Action c restores RPS to a reliabilit level equivalent to that evaluated in NEDC-30851P-A, which justified a 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> y allowable out of service time as allowed by Action b. To satisfy the requiremen Action c, the trip system in the more degraded state should be placed in trip or,ts of alternativ ely, all the inoperable channels in that trip system should be placed in trip (e.g., a trip system with two inoperable channels could be in a more degraded state than a trip system with four inoperable channels if the two inoperable channels are in the same Function while the four inoperable channels are all in different Functions). The decision of which trip system is in the mote degraded state sh6uld be based on prudent judgment and take into account current plant conditions Ci .e.,

what OPERATIONAL CONDITION the plant is in). If this action would result in a scram (

or RPT, it is permissible to place the other trip system or its inoperable channels in trip.

The 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowable out of service time is judged acceptable based on the remaining capability to trip, the diversity of the sensors available to provide the trip signals, the low probabilit y of extensive numbers of inoperabi lities affecting all diverse Functions, and the low probabilit y of an event requiring the initiation of a scram.

As noted, Action c is not applicable for APRM Functions 2.a, 2.b, 2.c, 2.d, or 2.f. Inoperabi lity of an APRM channel affects both trip systems and is not associated with a specific trip system as are the APRM 2-0ut-Of-4 voter and other non-APRM channels for which Action c applies. For an inoperable APRM channel, the requirements of Action b can only be satisfied by tripping the inoperable APRM channel. Restoring OPERABILITY or placing the inoperable APRM channel in trip are the only actions that will restore capability to accommodate a single APRM channel failure.

If it is not desired to place the channel (or trip system) in trip to satisfy the requirements of Action a, Action b or Action c (e.g., as in the case where placing the inoperable channel in trip would result in a full scram), Action d requires that the Action defined by Table 3.3.1-1 for the applicable Function be initiated immediately upon expiration of the allowable out of service time.

Table 3.3.1-1, Function 2.f, references Action 10, which defines the action required if OPRM Upscale trip capability is not maintained. Action lOb is required to address identified equipment failures. Action 10a is to address common mode vendor/industry identified issues that render all four OPRM channels inoperable at once. For this condition, References 2 and 3 justified use of (,

alternate methods to detect and suppress oscillatio ns for a limited period of LIMERICK - UNIT 2 B 3/4 3-lc Amendment No.~. ~

Associated with Amendment 196

3/4.3 INSTRUMENTATION B

3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION (continued) time, up to 120 days. The alternate methods are procedurally establishe d consisten t with the guidelines identified in Reference 7 requiring manual operator action to scram the plant if certain predefined events occur. The 12-hour allowed completion time to implement the alte~nate methods is based on engineering judgment to allow orderly transition to the alternate methods while limiting the period of time during which no automatic or alternate detect and suppress trip capability is formally in place. The 120-day period during which use of alternate methods is allowed is intended to be an outside limit to allow for the case where design changes or extensive analysis might be required to understand or correct some unanticipated character istic of the instabilit y detection algorithms or equipment. The evaluation of the use of alternate methods concluded, based on engineering judgment, that the likelihood of an instabilit y event that could not be adequately handled by the alternate methods during the 120-day period was negligibly small. Plant startup may continue while operating within the allowed completion time of Action 10a. The primary purpose of this is to allow an orderly completion, without undue impact on plant operation, of design and verificati on activities in the event of a required design change to the OPRM Upscale function. This exception is not intended as an

.alternativ e to restoring inoperable equipment to OPERABLE status in a timely manner.

Action lOa is not intended and was not evaluated as a routine alternativ e to returning failed or inoperable equipment to OPERABLE status. Correction of routine equipment failure or inoperabi lity is expected to be accomplished within the completion times allowed for LCO 3.3.1 Action a or Action b, as applicable .

Action 10b applies when routine equipment OPERABILITY cannot be restored within the allowed completion times of LCO 3.3.1 Actions a orb, or if a common mode OPRM deficiency cannot be corrected and OPERABILITY of the OPRM Upscale Function restored within the 120-day allowed completion time of Action lOa.

The OPRM Upscale trip output shall be automatically enabled *cnot-bypassed) when APRM Simulated Thermal Power is~ 29.5% and recirculat ion drive flow is< 60%

as indicated by APRM measured rec~rculation drive flow. NOTE: 60% recirculat ion drive flow is the recirculat ion drive flow that corresponds to 60% of rated core flow. This is the operating region where actual thermal-hydraulic instabilit y and related neutron flux oscillatio ns may occur. As noted in Table 4.3.1.1-1, Note c, CHANNEL CALIBRATION for the OPRM Upscale trip Function 2.f includes confirming that the auto-enab le (not-bypassed) setpoints are correct. Other surveillan ces ensure that the APRM Simulated Thermal Power properly correlates with THERMAL POWER (Table 4.3.1.1-1 , Noted) and that recirculat ion drive flow properly correlates with core flow (Table 4.3.1.1-1, Note g).

If any OPRM Upscale trip auto-enable setpoint is exceeded and the OPRM Upscale tr1p is not enabled, i.e., the OPRM Upscale trip is bypassed when APRM Simulated Thermal Power is~ 29.5% and recirculat ion drive flow is< 60%, then the affected channel is congidered inoperable for the OPRM Upscale Function.

Alternativ ely, the OPRM Upscale trip auto-enable setpoint(s ) may be adjusted to place the channel in the enabled condition (not-bypassed). If the OPRM Upscale trip is placed in the enabled condition, the surveillan ce requirement is met and the channel is considered OPERABLE.

LIMERICK - UNIT 2 B 3/4 3-ld Amendment No. J.9.,

Associated with Amendme nt~. 196

3/4.3 INSTRUMENTATION 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION (continued) (

As noted in Table 4.3.1.1- 1, Note g, CHANNEL CALIBRATION for Simulated Thermal Power - Upscale Function 2.b and the OPRM Upscale the APRM Function 2.f, includes the recircul ation drive flow input function. The APRM Simulated Thermal Power - Upscale Function and the OPRM Upscale Function both require a valid drive flow signal. The APRM Simulated Thermal Power - Upscale Function uses to vary the trip setpoint . The OPRM Upscale Function uses drive flow todrive flow automatically enable or bypass the OPRM Upscale trip output to RPS. A CHANNEL CALIBRATION of the APRM recircul ation drive flow input function requires both calibrat ing the drive flow transmit ters and establishing a valid drive flow/

core flow relationship. The drive flow/ core flow relation ship is once per refuel cycle, while operating within 10% of rated core flow establish and within ed 10% of RATED THERMAL POWER. Plant operational experience has shown that this flow correlation methodology is consistent with the guidance and intent Reference 8. Changes throughout the cycle in the drive flow/ core flow in relation ship due to the changing thermal hydraulic operating conditions of the core are accounted for in the margins included in the bases or analyses used to establis h the setpoints for the APRM Simulated Thermal Power - Upscale Function and the OPRM Upscale Function.

For the Simulated Thermal Power - Upscale Function (Function 2.b), the CHANNEL CALIBRATION surveillance requirement is modified by two Notes. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluatio performance will verify that the channel will continue to behaven inof accordan channel with safety analysis assumptions and the channel performance assumptions in ce setpoint methodology. The purpose of the ~ssessment is to ensure confidence the in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service

(

the performance of these channels will be evaluated under the plant Correcti ve Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition. The second Note requires as-left setting for the channel be within the as-left tolerance of thethat Trip the Setpoint. The as-left and as-found toleranc es, as applicable, will be applied to the surveillance procedure setpoint . This will ensure that to the Safety Limit and/or Analytical Limit is maintained. If sufficie nt margin the as-left channel setting cannot be returned to a setting within the as-left tolerance of the Trip Setpoint, then the channel shall be declared inoperable. The as-left toleranc e for this function is calculated using the square-root-sum-of-squa res of the reference accuracy and the measurement and test equipment error (including readabil ity). The as-found tolerance for this function is calculated using the square-root-sum-of-squares of the reference accuracy, instrume nt drift, and the measurement and test equipment error (including readabil ity).

To ensure that the APRMs are accurate ly indicati ng the true core average power, the APRMs are adjusted to the reactor power calculat a heat balance if the heat balance calculat ed reactor power exceedsedthefrom APRM channel output by more than 2% RTP.

This Surveill ance does not preclude making APRM channel if desired , when the heat balance calculat ed reactor power is adjustmless than ents, the APRM channel output. To provide close agreement between the APRM indicate d power and to preserve operatin g margin, the APRM channels are normally adjusted to within+ /- 2% of the heat balance calculat ed reactor However, this agreement is not required for OPERABILITY when APRM power.

indicate s a higher reactor power than the heat balance calculat ed output reactor power. (_

LIMERICK - UNIT 2 B 3/4 3-le Amendment No. ~.~.-l47.

Associated with Amendment~. 196

3/4.3 INSTRUMENTATION BA 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION (continued)

As noted in Table 3.3.1-2, Note"*", the redundant outputs from the 2-0ut-Of-4 Voter channel are considered part of the same channel, but the OPRM and APRM outputs are considered to be separate channels, so N = 8 to determine the interval between tests for application of Specification 4.3.1.3 (REACTOR PROTECTION SYSTEM RESPONSE TIME). The note further requires that testing of OPRM and APRM outputs shall be alternated.

Each test of an OPRM or APRM output tests each of the redundant outputs from the 2-0ut-Of-4 Voter channel for that function, and each of the corresponding relays in the RPS. Consequently, each of the RPS relays is tested every fourth cycle. This testing frequency is twice the frequency justified by References 2 and 3.

Automatic reactor trip upon receipt of a high-high radiation signal from the Main Steam Line Radiation Monitoring System was removed as the result of an analysis performed by General Electric in NED0-3l400A. The NRC approved the results of this analysis as documented in the SER (letter to George J. Beck, BWR Owner's Group from A.C. Thadani, NRC, dated May 15, 1991).

The measurement of response time at the frequencies specified in the Surveillance Frequency Control Program provides assurance that the protective functions associated with each channel are completed within the time limit assumed in the safety analyses. No credit was taken for those channels with response times indicated as not applicable except for the APRM Simulated Thermal Power - Upscale and Neutron Flux - Upscale trip functions and the OPRM Upscale trip function (Table 3.3.1-2, Items 2.b, 2.c, and 2.f). Response time may be demonstrated by any s~ries of sequential, overlapping or total channel test measurement, provided such tests demonstrate the total channel response time as defined. Sensor response time verification may be demonstrated by either (1) inplace, onsite or offsite test measurements, or (2) utilizing replacement sensors with certified response times. Response time testing for the sensors as noted in Table 3.3.1-2 is not required based on the analysis in NED0-32291-A.

Response time testing for the remaining channel components is required as noted.

For the digital electronic portions of the APRM functions, performance characteristics that determine response time are checked by a combination of automatic self-test*, calibration activities, and response time tests of the 2-0.ut-Of-4 Voter (Table 3.3.1-2, Item 2.e).

LIMERICK - UNIT 2 B 3/4 3-lf Amendment No. ~.~.-1-47-.

Associated with Amendment eJ, 196

rNSTRUMENTATI ON BASES 3/ 4, 3, 2 ISOLATION ACTUATION INSTRUMENTATION This specification ensures the effectiveness of the instrumentation used to mitigate the consequences of accidents by prescribing the OPERABILITY trip setpotnts and response times for isolation of the reactor systems. When necessary, one channel may be inoperable for brief intervals to conduct required surveillance.

• Surveillance intervals are determined in accordance with the Surveillance Frequency Control Progam and maintenance outage times have been determined in accordance with NEDC-30851P, Supplement 2, "Technical Spec.i fi cation Improvement Analysis for *BWR Instrumentation Common to RPS and ECCS Instrumentation" as approved by the NRC and documented in the NRC Safety Evaluation Report CSER)

(letter to D.N. Grace from C.E. Rossi dated January 6, 1989) and NEDC-31677P-A, "Technical Specification Improvement Analysis for BWR Isolation Actuation Instrumentation," as approved by the NRC and documented in the NRC SER (letter to S.D. Floyd from C.E. Rossi dated June 18, .1990).

Automatic closure of the MSIVs ufon receipt of a high-high radiation signal from the Main Steam Line Radiat on Monitoring System was removed as the result of an analysis performed by General Electric in NED0-31400A. The NRC approved the results of this analysis as documented in the SER (letter to George J. Beck, BWR Owner's Group from A.C. Thadani,*NRC, dated May 15, 1991).

Some of the trip settings may have tol~rances explicitly stated where both the high and low values are critical and may have a substantial effect on safety. The s~tpoints of other instrumentation, where only the high or low end of the setting have a direct bearing on safety, are established at a level away from the normal operating range to prevent inadvertent actuation of the systems involved.

Except for the MSIVs, the safety analysis does not address individual sensor response times or the response times of the logic systems to which the sensors are connected. For D.C. operated valves, a 3 second delay is assumed before the valve starts to move. For A.C. operated valves, it is assumed that the A.C.

power supply is lost and is restored by startup of the emergency diesel generators. In this event, a time of 13 seconds is assumed before the valve starts to move. In addition to the pipe break, the failure of the D.C. operated valve is assumed; thus the signal delay (sensor response) is concurrent with the 10-second diesel startup and the 3 second load center loading delay. The safety analysis considers an allowable inventory loss in each case which in turn determines the valve speed in conjunction with the 13-second delay. It follows that checking the valve speeds and the 13-second time for emergency power establishment will establish the response time for the isolation functions.

• Response time testing for sensors are not required based on the analysis in NED0-32291-A. Resporise time testing of the remaining channel components is required as noted in Table 3.3.2-3.

• Operation with a trip set less conservative than its Trip Setpoint but within ,ts specified Allowable Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is an allowance for instrument drift specifically allocated for each trip in the safety analyses. Primary containment isolation valves that are actuated by the isolation signals specified in Technical Specification Table 3.3.2-1 are identified in Technical Requirements Manual Table 3.6.3-1.

• 3/4, 3, 3 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION The emergency core cooling system actuation instrumentation is provided to initiate actions to mitigate the consequences of accidents that are beyond the **c*

I.

ability of the operator to control. This specification provides the OPERABILITY '.*.~,W-requirements, trip setpoints and response times that will ensure effectiveness of the systems to provide the design protection. Although the instruments are listed by system, in some cases the same instrument may be used to send the actuation signal to more than one system at the same time.

I TlJ ... n.Tru Ill! TT" 'l 0 "'l /A "'l ? ,.,..,..,~ ....... + IIJ,.. l1 11 i;._1 Q.'.2 111.2 1 A-,

INSTRUMENTATION BASES 3/4,3.3 EMERGENCY CORE COOtING SYSTEM ACTUATION INSTRUMENTATION (Continued)

Surveillanc e intervals are determined in accordance with the Surveillance Frequency Control Program and maintenance outage time, have been determined in accordance with NEDC-30936P, Parts 1 and 2, "Technical Specificatio n Improvement Methodology (with Demonstration for BWR ECCS Actuation Instrumenta tion)," as approved by.the NRC and docµmented in the SER (letter to D. N. Grace from A. C.

Thadani dated December 9, 1988 (Part 1) and letter to D. N. Grace from C. E.

Rossi dated December 9, 1988 (Part 2)).

Successful operation of the required safety functions of the Emergency Core Cooling Systems (ECCS) is dependent upon the availability of adequate power for energizing various components such as pump motors, motor operated valves, and the associated control components. If the loss of po~er instrumenta tion detects that voltage levels are too low, the buses are disconnected from the offsite power sources and connected to*the onsite diesel generator COG) power sources. The loss of power relays in each channel have sufficient overlapping detection characteris tics and functionalit y to permit operation subject to the conditions in Action Statement 37. Bases 3/4.8.1, 3/4.8.2, and 3/4.8.3 provide discussion regarding parametric bounds for determining operability of the offsite sources.

Those Bases assume that the loss of power relays are operable. With an inoperable 127Z-11XOX relay, the grid voltage is monitored to 230kV (for the 101 Safeguard Bus Source) or 525kV (fa~ the 201 Safeguard Bus Source) to increase the margin for the operation of the 127Z-11XOX relay.

Operation with a trip set less conservative than its T~ip Setpoint but within its specified Allowable Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is an allowance for instrument drift specifically all~cated for each trip in the safety analyses.

3/4.3,4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION The anticipated transient without scram (ATWS) recirculatio n pump trip system provides a means of limiting the ,consequences of the unlikely occurrence of a failure to scram during an anticipated transient. The response of the plant to this postulated event falls within the envelope of study events in General Electric Company Topical Report NED0-10349, dated *March 1971, NED0-24222, dated December 1979, and Section 15.8 of the FSAR.

The end-of-cycle recirculatio n pump trip (EOC-RPT) system is a supplement to the reactor trip. During turbine trip and generator load rejection events, the EOC-RPT will reduce the likelihood of reactor vessel lev~l decreasing to level

2. Each EOC-RPT system trips both recirculatio n pumps, reducing coolant flow *in order to reduce the void collapse in the core during two of the most limiting pressurizati on events. The two events for which the EOC-RPT protective feature will function are closure of the turbine stop valves and fast closure of the turbine control valves.

A fast closure sensor from each of two turbine control valves provides input to the EOC-RPT system; a fast closure sensor from each of the other two turbine control valves provides input to the* second EOC-RPT system. Similarly, a position switch for each of two turbine stop valves provides input to one EOC-RPT system; a position switch from each of the other two stop valves provides input to the other EOC-RPT system. For each EOC-RPT system, the sensor relay contacts are arranged*to form a 2-out-of~2 logic for the fast closure of turbine control valves and a 2-out-of-2 logic for the turbine stop valves. The operation of either logic will actuate the EOC-RPT system and trip both recirculatio n pumps.

LIMERICK - UNIT 2 B 3/4 3-3 Amendment No. +7,J..i,JJ,~ , 147

INS TRUMENTATI ON

, ; .B;. .AS_E..,S_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ r 3/4,3,4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION (Continued)

Each EOC-RPT system may be manually bypassed by use of a keyswitch which is administratively controlled. The manual bypasses and the automatic Operating Bypass at less than 29.5% of RATED THERMAL POWER are annunciated 1n the control room.

The EOC-RPT system response time is the time assumed in the analysis between initiation of valve motion and complete suppression of the electric arc, i.e.,

175 ms. Included in this time are: the response time of the sensor, the time allotted for breaker arc suppression, and the response time of the system logic.

(

LIMERICK* UNIT 2 B 3/4 3-3a Amendment No.~.

Associated with Amendment 163

INSTRUMENTATION BASES Surveil lance interva ls are determined in accordance with the Surveil lance Frequency Control Program and maintenance outage times have been determiInterva ned in accordance with GENE-770-06-1, "Bases for Changes to Surveil lance Test ls and Allowed Out-of- Service Times for Selecte d Instrum entatio n Technic al Specif ication s," as approved by the NRC and documented in the SER (letter to R.D.

Binz, IV, from C.E. Rossi dated July 21, 1992).

Operation with a trip set less conservative than its Trip Setpoin t but within its specifi ed Allowable Value is acceptable on the basis that the ce differe nce between each Trip Setpoin t and the Allowable Value is an allowan for instrum ent drift specifi cally allocat ed for each trip in the safety analyse s.

3/4.3.5 REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION The reactor core isolatio n cooling system actuati on instrum entatio n is provided to initiat e actions to assure adequate core cooling in the event of reactor isolati on from its primary heat sink and the loss of feedwa ter flow to the reactor vessel. This instrumentation does not provide actuati on of any of the emergency core cooling equipment.

Surveil lance interva ls are determined in accordance with the Surveil lance Frequency Control Program and maintenance outage times have been specifi ed in accordance with recommendations made by GE in their letter to the BWR Owner's Group dated August 7, -1989,

SUBJECT:

"Clarif ication of Technical Specifi cation changes given in ECCS Actuation Instrumentation Analys is."

Operation with a trip set less conservative than its Trip Setpoin t but within its specifi ed Allowable value is acceptable on the basis that allowan the differe nce between each Trip Setpoin t and the Allowable Value is an ce for instrum ent drift specifi cally allocat ed for each trip in the safety analyse s.

3/4.3.6 CONTROL ROD BLOCK INSTRUMENTATION The control rod block functio ns are provided consist ent with the requirements of the specifi cations in Section 3/4.1.4 , Control Rod Program Controls and Section 3/4.2 Power Distrib ution Limits and Section 3/4.3 Instrum entatio n. The trip logic is arranged so that a trip in any one of the inputs will result in a control rod block.

Surveil lance interva ls are determined in accordance with the Surveil lance Frequency Control Program and maintenance outage time have been determined ment in accordance with NEDC-30851P, Supplement 1, "Techn ical Specifi cation Improve Analysis for BWR Control Rod Block Instrum entatio n," as approved by the NRC erand22, documented in the SER (letter to D. N. Grace from C. E. Rossi dated Septemb .

1988).

Operation with a trip set less conserv ative than its Trip Setpoin t but within its specifi ed Allowable Value is accepta ble on the basis that allowan the differe nce between each Trip Setpoin t and the Allowable Value is an ce for instrument drift specifi cally allocat ed for each trip in the safety analyse s.

LIMERICK - UNIT 2 B 3/4 3-4 Amendment No. 1-J:., -l-7, ~. 147

INTENTIONALLY LEFT BLANK C

l I

INSTRUMENTATION BASES 3/4.3.7 MONITORING INSTRUMENTATION 3/4.3.7.1 RADIATION MONITORING INSTRUMENTATION The OPERABILITY of the radiation monitoring instrumentation ensures that:

(1) the radiation levels are continually measured in the areas served by the individual channels, and (2) the alarm or automatic action is initiated when the radiation level trip setpoint is exceeded, and (3) sufficient information is available on selected plant parameters to monitor and assess these variables following an accident. This capability is consistent with 10 CFR Part 50, Appendix A, General Design Criteria 19, 41, 60, 61, 63, and 64.

The surveillance interval for the Main Control Room Normal Fresh Air Supply Radiation Monitor is determined in accordance with the Surveillance Frequency Control Program.

3/4.3.7.2 (Deleted) - INFORMATION FROM THIS SECTION RELOCATED TO THE UFSAR.

3/4.3.7.3 (Deleted) - INFORMATION FROM THIS SECTION RELOCATED TO THE ODCM.

3/4.3.7.4 REMOTE SHUTDOWN SYSTEM INSTRUMENTATION AND CONTROLS The OPERABILITY of the remote shutdown system instrumentation and controls ensures that sufficient capability is available to permit shutdown and maintenance of HOT SHUTDOWN of the unit from locations outside of the control room. This capability is required in the event control room habitability is lost and is consistent with General Design Criterion 19 of 10 CFR Part 50, Appendix A. The Unit 1 RHR transfer switches are included only due to their potential impact on the RHRSW system, which is common to both units.

• 3/4.3.7.5 ACCIDENT MONITORING INSTRUMENTATION The OPERABILITY of the accident monitoring instrumentation ensures that sufficient information is available on selected plant parameters to monitor and assess important variables following an accident. This capability is consistent with the recommendations of Regulatory Guide 1.97, "Instrumentation for Light Water Cooled Nuclear Power Plants to Assess Plant Conditions During and Following an Accident,"

December 1975 and NUREG-0737, "Clarification of TMI Action Plan Requirements,"

November 1980.

Table 3.3.7.5-1, Accident Monitoring Instrumentation, Item 2, requires two OPERABLE channels of Reactor Vessel Water Level monitoring from each of two overlapping instrumentation loops to ensure monitoring of Reactor Vessel Water Level over the range of -350 inches to +60 inches. Each channel is comprised of one OPERABLE Wide Range Level instrument loop (-150 inches to +60 inches) and one OPERABLE Fuel Zone Range instrument loop (-350 inches to -100 inches). Both instrument loops, Wide Range and Fuel Zone Range, are required by Tech. Spec. 3.3.7.5 to provide sufficient overlap to bound the required range as described in UFSAR Section 7.5.

Action 80 is applicable if the required number of instrument loops per channel (Wide Range and Fuel Zone Range) is not maintained.

LIMERICK - UNIT 2 B 3/4 3-5 Amendment No. -l-+/-,-+/--7,JJ.,~.~.

[CR 02 00470,~,-+/-47. ECR LG 09-00585

INSTRUMENTATION BASES

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3/4,3.7,5 ACCIDENT MONITORING INSTRUMENTATION (continued)

Table 3.3.7.5-1, Accident Monitoring Instrumentation, Item 13, requires two OPERABLE channels of Neutron Flux monitoring from each of three overlapping instrumentation loops to ensure monitoring of Neutron Flux over the range of 10" 6% to 100% full power. Each channel is comprised of one OPERABLE SRM (10. 9% to 10* 3% power),

one OPERABLE IRM (10" 4% to 40% power) and one OPERABLE APRM (0% to 125% power). All three instrument loops, SRM, IRM and APRM, are required by Tech. Spec. 3.3.7.5 to provide sufficient overlap to bound the required range as described in UFSAR Section 7.5. Action 80 is applicable if the required number of instrument loops per channel (SRM, IRM, and APRM) is not maintained.

3/4.3,7,6 SOURCE RANGE MONITORS The source range monitors provide the operator with information of the status of the neutron level in the core at ve~y low power levels during startup and shutdown.

At these power levels, reactivity additions shall not be made without this flux level information available to the operator. When the intermediate range monitors are on scale, adequate information is available without the SRMs and they can be retracted.

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LIMERICK - UNIT 2 B 3/4 3-Sa Amendment No. -i-1-,+7.~.~.~

ECR LG 09-00585

INSTRUMENTATION BASE 3/4.3.7.7 (Deleted) - INFORMATION FROM THIS SECTION RELOCATED TO THE TRM.

3/4.3.7.8 CHLORINE AND TOXIC GAS DETECTION SYSTEMS The OPERABILITY of the chlorine and toxic gas detection systems ensures that an accidental chlorine and/or toxic gas release will be detected promptly and the necessary protective actions will be automaticall y initiated for chlo-rine and manually initiated for toxic gas to provide protection for control room personnel. Upon detection of a high concentration of chlorine, the control room emergency ventilation system will automatically be placed in the chlorine isolation mode of operation to provide the required protection. Upon detection of a high concentratio n of toxic gas, the control room emergency ventilation

• system will manually be placed in the chlorine isolation mode of operation to provide the required protection. The detection systems required by this speci-fication are consistent with the recommendations of Regulatory Guide 1~95, "Pro-tection of Nuclear Power Plant Control Room Operators against an Accidental Chlorine Release," February 1975.

There are three toxic gas detection subsystems. The high toxic chemical concentratio n alarm in the Main Control Room annunciates when two of the three subsystems detect a high toxic gas concentratio n. An Operate/lnop keylock switch is provided for each subsystem which allows an individual subsystem to be placed in the tripped condition. Placing the keylock switch in the INOP position initiates one of the two inputs required to initiate the alarm in the Main Control Room.

Surveillanc e intervals are determiried in accordance with the Surveillance Freqtiency Control Program and maintenance outage times have been determined in accordance with GENE-770-06-1, "Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specificatio ns," as approved by the NRC and documented in the SER (letter to R.D.

Binz, IV, from C.E. Rossi dated July 21, 1992).

3/4.3.7.9 (Deleted) - INFORMATION FROM THIS SECTION RELOCATED TO THE TRM.

LIMERICK - UNIT 2 B 3/4 3-6 Amendment No. 1+/-,.is,~.4-a.,eg,-7-9-, 147

(INTENTIONALLY LEFT BLANK)

(

l_

INSTRUMENT ATI ON ASE 3/4.3.7.10 (Deleted) 3/4.3.7.11 (Deleted) - INFORMATION FROM THIS SECTION RELOCATED TO THE ODCM.

3/4.3.7.12 (Deleted) - INFORMATION FROM THIS SECTION RELOCATED TO THE ODCM AND THE TRM.

3/4.3.8 (Deleted) - INFORMATION FROM THIS SECTION RELOCATED TO THE UFSAR.

3/4.3.9 FEEDWATER/MAIN TURBINE TRIP SYSTEM ACTUATION INSTRUMENTATION The feedwater/main turbine trip system actuation instrumentation is provided to initiate action of the feedwater system/main turbine trip system in the event of failure of feedwater controller under maximum demand.

REFERENCES:

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

2. NEDC-32410P-A, "Nuclear Measurement Analysis and Control Power Range Neutron Monitor (NUMAC PRNM) Retrofit Plus Option III Stability Trip Function," October 1995.

3. NEDC-32410P-A, Supplement 1, "Nuclear Measurement Analysis and Control Power Range Neutron Monitor (NUMAC PRNM) Retrofit Plus Option III Stability Trip Function," November 1997.

4. NED0-31960-A, "BWR Owners' Group Long-Term Stability Solutions Licensing Methodology," November 1995.

5. NED0-31960-A, Supplement 1, "BWR Owners' Group Long-Term Stability Solutions Licensing Methodology," November 1995.

6. NED0-32465-A, "Reactor Stability Detect and Suppress Solutions Licensing Basis Methodology for Reload Applications," August 1996.

7. Letter, L.A. England (BWROG) to M. J. Virgilio, "BWR Owners' Group Guidelines for Stability Interim Corrective Action," June 6, 1994.

8. GE Service Information Letter No. 516, "Core Flow Measurement - GE BWR/3, 4, 5 and 6 Plants," July 26, 1990.

9. GE Letter NSA 00-433, Alan Chung (GE) to Sujit Chakraborty (GE),

"Minimum Number of Operable OPRM Cells for Option III Stability at Limerick 1 & 2," May 02, 2001.

LIMERICK - UNIT 2 B 3/4 3-7 Amendment No.+/-+/-,-&§.,~. -e-4-, -e&,

-l-l-7-, ~ . 191

-,-* WATER I..EVEL NCIIIENCLATURE.

• 'NOT1!: SCALE N INCHES ABOVE VESSELZERO HEDff ABOVE**

NO. VESSEi.ZERO

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C3) 111.S 511.5

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(I) 311.5 . -,a.o

• ~'°L.r,s,-usa.

7DD l50 I.PSET

• fWGE IGO CATION IOffl:IM .

ONLY) 0, STEAM 5!50 D

• DIIYSI SICIAT .

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• Wide " " u,wial This lldcllOh II 18Wr CDOll,II . . . . . . . . . . . . . . . . The CllitnllOn

• 11111 ...... mra9d CDIICIIIIICII .. The llvel "'°'

. . . . . . . . . tllfflpnlurN, . . . . . . . . . . ...., . . . .

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wtlictl IWfllCll1'1e . . . . DkllDWI . . . . . - - - fllll Ht BASES FIGURE B 3/4.3*1 REACTOR VESSEL WATER LEVEL LIMERICK* UNIT 2 B 3/4 3*8 AU& Z 5 1919

\ .

LPRM 1 LPRM 3 LPRM 2 LPRM 4 APRM 1 APRM 3 APRM 2 APRM 4 APRM APRM .APRM APRM 2-0UT-OF-4 2-0UT-OF-4 2-0UT-OF-4 2-0UT-OF-4 VOTER A1 VOTER A2 VOTER 81 VOTER 82

-)

RPS CHANNEL .A1 RPS CHANNEL AZ RPS CHANNEL 81 RPS CHANNEL 82 RELAYS Kl2A. & Kl2E RELAYS Kl2C & Kl2G RELAYS Kl2B & Kl2F RELAYS*K12D & Kl2H BASES FIGURE B 3/4.3-2 APRM CONFIGURATION LIMERICK - UNIT 2 83/4 3-9 P.na rlreut 1'b. lOJ

l

3/4.4 REACTOR COOLANT SYSTEM

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3/4.4.1 RECIRCULATION SYSTEM The impact of single recirculatio n loop operation upon plant safety is assessed and shows that single-loop operation is permitted if the MCPR fuel cladding safety limit is increased as noted by Specificatio n 2.1.2, APRM scram and control rod block setpoints are adjusted as noted in Tables 2.2.1-1 and 3.3.6-2, respectively .

An inoperable jet pump is not, in itself, a sufficient reason to declare a recirculatio n loop inoperable, but it does, in case of a design-basis -accident, increase the blowdown area and reduce the capability of reflooding the core; thus.-

the requirement for shutdown of the facility with a jet pump inoperable. Jet pump failure can be detected by monitoring jet pump performance on a prescribed schedule for significant degradation.

Additionally , surveillance on the pump speed of the operating recirculatio n loop is imposed to exclude the possibility of excessive internals vibration. The surveillance on differential temperatures below 30%

RATED THERMAL POWER or 50% rated recirculatio n loop flow is to mitigate the undue thermal stress on vessel nozzles, recirculatio n pump and vessel bottom head during the extended operation of the single recirculatio n loop mode.

Surveillance of recirculatio n loop flow, total core flow, and diffuser-to-lower plenum differential pressure is designed to detect significant degradation in jet pump performance that precedes jet pump failure. This surveillance is required to be performed only when the loop has forced recirculatio n flow since surveillance checks and measurements can only be performed during jet pump operation. The jet pump failure of concern is a complete mixer displacement due to jet pump beam failure. Jet pump plugging is also of concern since it adds flow resistance to the recirculatio n loop. Significant degradation is indicated if the specified criteria confirm unacceptable deviations from established patterns or relati.onship s. Since refueling activities (fuel assembly replacement or shuffle, as well as any modification s to fuel support orifice size or core plate bypass flow) can affect the relationship between core flow, jet pump flow, and recirculatio n loop flow, these relationship s may need to be re-establish ed each cycle. Similarly, initial entry into extended single loop operation may also require establishmen t of these relationship s. During the initial weeks of operation under such conditions, while base-lining new "established patterns," engineering judgment of the daily surveillance results is used to detect significant abnormalitie s which could indicate a jet pump failure.

The recirculatio n pump speed operating characterist ics (pump flow and loop flow versus pump speed) are determined by the flow resistance from the loop suction through the jet pump nozzles. A change in the relationship indicates a plug, flow restriction, loss in pump hydraulic performance, leakage, or new flow path between the recirculatio n pump discharge and jet pump nozzle. For this criterion, the pump flow and loop flow versus pump speed relationship must be verified.

LIMERICK - UNIT 2 B 3/4 4-1 Amendment No. ,4.g,-+/-J-9.,

Associated with Amendment 157

REACTOR COOLANT SYSTEM

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3/4.4.1 RECIRCULATION SYSTEM (continued)

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

The deviations from normal are considered indicative of a potential problem

~n the recirculation drive flow or jet pump system. Normal flow ranges and established jet pump flow and differential pressure patterns are established by plotting historical data.

Recirculation pump speed mismatch limits are in compliance with the ECCS LOCA analysis design criteria for two recirculation loop operation. The limits will ensure an adequate core flow coastdown from either recirculation loop following a LOCA. In the *case where the mismatch limits cannot be maintained during two loop operation, continued operation is permitted in a single recirculation loop mode.

In order to prevent undue stress on the vessel nozzles and bottom head (

region, the recirculation loop temperatures shall be within S0°F of each other prior to startup of an idle loop. The loop temperature must also be within 50°F of the reactor pressure vessel coolant temperature to prevent thermal shock to the recirculation pump and recirculation nozzles. Sudden equalization of a temperature difference> 145°F between the reactor vessel bottom head coolant and the coolant in the upper region of the reactor vessel by increasing core flow rate would cause undue stress in the reactor vessel bottom head.

3/4.4.2 SAFETY/RELIEF VALVES The safety valve function of the safety/relief valves operates to prevent the reactor coolant system from being pressurized above the Safety Limit of 1325 psig in accordance with the ASME Code. A total of 12 OPERABLE safety/

relief valves is required to limit reactor pressure to within ASME III allow-able values for the worst case upset transient.

Demonstration of the safety/relief valve lift settings will occur only during shutdown. The safety/relief valves will be removed and either set pressure tested or replaced with spares which have been previously set pres-sure tested and stored in accordance with manufacturers recommendations at the frequency specified in the Surveillance Frequency Control Program.

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LIMERICK - UNIT 2 B 3/4 4-2 Amendment No. -9&,~.+47.

Associated with Amendment 157

REACTOR COOLANT SYSTEM *

\ 3/4~4.3 REACTOR COOLANT SYSTEM LEAKAGE 3/4.4.3.1 LEAKAGE DETECTION SYSTEMS BACKGROUND UFSAR.Safet~ Design.Basis (Ref. +), requires means for detecting and, to the extent practical, identifying the location of the source of Reactor Coolant System (RCS)

PRESSURE BOUNDARY LEAKAGE. Regulatory Guide 1.45, Revision 0, (Ref. 2) describes acceptable methods for selecting leakage detection syste~s. .

Limits on leakage from the reactor coolant pressure boundary (RCPB) are required so that appropriate action can be taken before the integrity of the RCPB is impaired (Ref.

2). Leakage detection systems for the RCS are provided to alert the operators whe~

leakage rates above normal background levels are detected and also to supply quantitative measurement of leakage rates .. In addition to meeting the OPERABILITY requirements, the monitors are typically set to provide the most sensitive response without causing an excessive number of spurious alarms.

Systems for quantifying the leakage are necessary to provide prompt and quantitative information to the operators to permit them to take immediate corrective action.

Leakage from the RCPB inside the drywell is detected by at least one of four (4) independently monitored variables which include drywell sump flow monitoring equiP.ment with the required RCS leakage detection instrumentation (i.e., the drywell floor drain sump flow monitoring system, or, the drywell equipment drain sump monitoring system with the drywell floor drain sump overflowing to the drywell equipment drain sump) drywell gaseous radioactivity, drywell unit cooler condensate flow rate and dryweli.

pressure/temperature levels .. The primary means of quantifying leakage in the arywell is the drywell sump monitorin~ system for UNIDENTIFIED LEAKAGE and the drywell equipment drain tank flow monitoring *system for IDENTIFIED LEAKAGE. IDENTIFIED leakage is not germane to this Tech Spec and the associated drywell equipment drain tank flow monitoring system is not included.

_) The drywell floor drain sump flow monitoring system monitors UNIDENTIFIED LEAKAGE collected in the floor drain sump. UNIDENTIFIED LEAKAGE consists of leakage from RCPB components inside the drywell which are not normally subject to leakage and otherwise routed to the drywell equipment drain sump. The *primary containment floor drain sump

.0 , has.tra~smitter s that suQply leve1 indication to the '!'ain control *roo'!' via t~e plant

- monitoring system. The floor drain sump level transmitters are associated with High/Low level switches that open/close the sump tank drain valves automatically. The level instrument P.rocessing unit calculatas an average l~ak rate (gpm) for a given measurement period which resets whenever the sump drain valve closes. The level processing unit provides an alarm to the main control .room each time the average leak rate changes by a predetermine~ value since the last time the alarm was reset. For the drywell floor drain sump flow monitoring system, the setpoint basis is a 1 gpm change in UNIDENTIFIED LEAKAGE. .

• An alternate to the drywell floor drain sump flow monitoring system for quantifying UNIDENTIFIED LEAKAGE is the drywell equipment drain sump monitoring system, if the drywell floor drain sump is overflowing to the drywell equipment drain sump. In this configuration, the drywell equipment drain sump collects all leakage into the drywell equiP.ment drain sump and the overflow from the*drywell floor drain sump. Therefore, if the drywell floor 'drain sump is overflowing to the drywell equipment drain sump, the drywell equipment drain sump monitoring system can be used to guantify UNIDENTIFIED LEAKAGE. In this condition, all leakage measured by the drywell equipment drain sump

.monitorin~ system is assumed to be UNIDENTIFIED LEAKAGE. The leakage determination process, including the transition to and use of the alternate method is described in station procedures. The alternate method would only be used when the drywell floor drain sump flow monitoring system is unavailable.

In addition to the drywell sump monitoring system described above, the discharge of each sump is monitored bY an independent flow element. The measured flow rate from the flow element is integrated and recorded. A main control room alarm is also provided to indi.cate an excessive sump discharge rate measured via the flow element. This system, referred to as the "drywell floor drain flow totalize~". is not credited for drywell

~ floor drain sump flow monitoring system operability.

LIMERICK - UNIT 2 B 3/4 4-3 Amendment No.~.~.

Associated with Amendment No. e+, 169

REACTOR COOLANT SYSTEM BACKGROUND (Continued)

The primary containment atmospheric gaseous radioactivity monitoring system C

continuously monitors the primary containment atmosphere for gaseous radioactivfty levels. A sudden increase of radioactivity, which may be attributed to RCPB steam or reactor water leakage, is annunciated in the main control room.

Condensata from the eight drywell air coolers is routed to the drywell floor drain sump and is monitored by a series of flow transmitters that provide indication and alarms in the main control room. The outputs from the flow transmitters are added together by summing units to provide a total continuous condensate drain flow rate. The high flow alarm setpo1nt is based on condensate drain flow rate in excess of 1 gpm over the currently identified preset leak rate. The drywell air cooler condensate flow rate monitoring system serves as an added indicator, but not quantifier, of RCS UNIDENTIFIED LEAKAGE (Ref. 4).

The drywell temperature and pressure monitoring systems provide an indirect method for detecting RCPB leakage. A temperature and/or pressure rise in the drywell above normal levels may be indicative of a reactor coolant or steam leakage (Ref. 5).

APPLICABLE SAFETY ANALYSES A threat of significant compromise to the RCPB exists if the barrier contains a crack that is large enough to propagate rapidly. Leakage rate limits are set low enough to detect the leakage emitted from a single crack in the RCPB (Refs. 6 and 7).

A control room alarm allow the operators to evaluate the significance of the indicated leakage and, if necessary shut down the reactor for further investigation and corrective action. The ailowed leakage rates are well below the rates predicted for critical crack sizes (Ref. 7). Therefore, these actions provide adequate response before a significant break in the RCPB can occur.

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

Statement.

LIMITING CONDITION FOR OPERATION <LCOl This LCO requires instruments of diverse monitoring principles to be OPERABLE to provide confidence that small amounts of UNIDENTIFIED LEAKAGE are detected in time to allow actions to place the plant in a safe condition, when RCS leakage indicates possible RCPB degradation. .

The LCO requires four instruments to be OPERABLE.

The required instrumentation to quantify UNIDENTIFIED LEAKAGE from the RCS consi'sts of either the drywell floor drain sump flow monitoring system, or, the drywell equipment drain sump monitoring system with the drywell floor drain sump overflowing to the drywell equipment drain sump. For either system to be considered operable, the flow monitoring portion of the system must be operable. The identification of an increase in UNIDENTIFIED LEAKAGE will be delayed by the time required for the UNIDENTIFIED LEAKAGE to travel to the drywell floor drain sump and it may take longer than one hour to detect a 1 gpm increase in UNIDENTIFIED LEAKAGE, depending on the origin and .

magnitude of the leakage. This sensitivity is acceptable for containment sump monitor OPERABILITY.

The reactor coolant contains radioactivity that, when released to the primary containment can be detected by the gaseous primary containment atmos~heric radioactivity monitor. A radioactivity detection system is included for monitoring gaseous activities because of its sensitivity and rapid response to RCS leakage, but it has recognized limitations. Reactor coolant radioactivity leveli will be low during initial reactor startup and for a few weeks thereafter, until activated corrosion products have been formed and fission products ap~ear from fuel element cladding (

contamination or cladding defects. If there are few fuel element cladding defects and "-

low levels of activation products, 1t may not be possible for the gaseous *primary LIMERICK - UNIT 2 B 3/4 4-3a Amendment No.~.

Associated with Amendment No.'*&+, 169

REACTOR COOLANT SYSTEM

\

/

LIMITING CONDITION FOR OPERATION (LCO) (Continued) containment atmospheric radioactivity monitor to detect a 1 gpm increase within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> during normal operation. However, the gaseous primary containment atmospheric radioactivity monitor is OPERABLE when it is capable of detecting a 1 gpm increase in UNIDENTIFIED LEAKAGE within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> given an RCS activity equivalent to that assumed in the design calculations for the monitors (Reference 9).

The LCO is satisfied when monitors of diverse measurement means. are available. Thus, the drywell floor drain sump monitoring system in combination with a gaseous primary containment atmospheric radioactivity monitor, a primary containment air cooler*

condensate flow rate monitoring iystem, and a primary containment pressure and temperature monitoring system provides an acceptable minimum.

APPLICABILITY In OPERATIONAL CONDITIONS l, 2, and 3, leakage detection systems are required to be OPERABLE to support LCD 3.4.3.2. This applicability is consistent with that for LCO 3.4.3.2.

ACTIONS A. With the primary containment atmosphere gaseous monitoring system inoperable, grab samples of the primary containment atmosphere must be taken and analyzed to provide periodic leakage information. [Provided a sample is obtained and analyzed once every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, the plant may be operated for up to 30 days to allow restoration of the radioactivitY. monitoring system. The plant may continue operation since other forms

__) of drywell leakage detection are available.]

The 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> interval provides periodic information that is adequate to detect leakage. The 30 day Completion Time for Restoration recognizes other forms of leakage detection are available.

B. With required drywell sump monitoring system inoperable, no other form of sampling can provide the equivalent information to quantify leakage at the required 1 gpm/hour sensitivity. However, the primary containment atmospheric gaseous monitor [and the primary containment air cooler condensate flow rate monitor] will provide i ndi cation of changes in 1eaka_ge.

With required drywell sump monitoring system inoperable; drywell condensate flow rate monitoring frequency increased from 12. to every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, and UNIDENTIFIED LEAKAGE and total leakage being determined every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> (Ref: SR 4.4.3.2.1.b) operation may continue for 30 days. To the extent practical, the surveillance frequency change associated with the drywell condensate flow rate monitoring system, makes up for the loss of the drywell floor drain sump monitoring system which had a normal surveillance requirement to monitor leakage every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. Also note that in

• this instance, the drywell floor drain tank flow totalizer will be used to comply with SR 4.4.3.2.1.b. The 30 day Completion Time of the required ACTION is acceptable, based on operating experience, considering the multiple forms of leakage detection that are still available.

C. With the required primary containment air cooler condensate flow rate monitoring system inoperable, SR 4.4.3.1.a must be performed every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> to provide periodic information of activity in the primary containment at a more frequent interval than the routine frequency of every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> interval provides periodic information that is adequate *to detect leakage and recognizes that other forms of leakage detection are available. The required ACTION has been clarified to state LIMERICK - UNIT 2 B 3/4 4-3b Amendment No.~.~.

Associated with Amendment No.~. 169

REACTOR COOLANT SYSTEM ACTIONS (Contjnued) that the additional surveillance requirement is not applicable if the required primary containment atmosphere gaseous radioactivity monitoring system is also inoperable. Consistent with SR 4.0.3, surveillances are not required to be performed on inoperable equipment. In this case, ACTION Statement A. and E.

requirements apply.

D. With the primary containment pressure and temperature monitoring system inoperable, operation may continue for up to 30 days given the system's indirect capability to detect RCS leakage. However, other more limiting Tech Spec requirements associated with the primary containment pressure/temperature monitoring system will still apply.

E. With both the primary containment atmosphere gaseous radioactivity monitor and the primary containment air cooler condensate flow rate monitor inoperable, the only means of detecting leakage is the drywell floor drain sump monitor and the drywell pressure/temperature instrumentation. This condition does not provide the required diverse means of leakage detection. The required ACTION is to restore either of the inoperable monitors to OPERABLE status within 30 days to regain the intended leakage detection diversity. The 30 day Completion Time ensures that the plant will not be operated in a degraded configuration for a lengthy time period. While the primary containment atmosphere gaseous radioactivity monitor is INOPERABLE, primary containment atmospheric grab samples will be taken and analyzed every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> since ACTION Statement A. requirements also appl1.

F. With the drywell floor drain sump monitoring system inoperable and the drywell unit (

coolers condensate flow rate monitoring system inoperable, one of the two remaining

• means of detecting leakage is the primary containment atmospheric gaseous radiation monitor. The primary containment atmospheric gaseous radiation monitor typically cannot detect a 1 gpm leak within one hour when RCS activity is low. Indirect methods of monitoring RCS leakage must be implemented. Grab samples of the primary containment atmosphere must be taken and analyzed and monitoring of RCS leakage by administrative means must be performed every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to provide alternate periodic information.

Administrative means of monitoring RCS leakage include monitoring and trending parameters that may indicate an increase in RCS leakage. There are diverse alternative mechanisms from which appropriate indicators may be selected based on plant conditions. It is not necessary to utilize all of these methods, but a method or methods should be selected considering the current plant conditions and historical or expected sources of UNIDENTIFIED LEAKAGE. The administrative methods are the drywell cooling fan inlet/outlet temperatures, drywell equipment drain sump temperature indicator, drywell equipment drain tank hi temperature indicator, and drywell equipment drain tank flow indicator. These indications, coupled with the atmospheric grab samples, are sufficient to alert the operating staff to an unexpected increase in UNIDENTIFIED LEAKAGE.

In addition to the primary containment atmospheric gaseous radiation monitor and indirect methods of monitoring RCS leakage, the primary containment pressure and temperature monitoring system is also available to alert the operating staff to an unexpected increase in UNIDENTIFIED LEAKAGE.

(

LIMERICK - UNIT 2 B 3/4 4-3c Amendment~ .~. -i-4-7 Associated w1th Amendment No. 167

REACTOR COOLANT SYSTEM B

) ACTIONS'"(Coritinued)

The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> interval is sufficient to detect increasing RCS leakage. The Required Action provides 7 days to restore another RCS leakage monitor to OPERABLE status

• to regain the intended* leakage- detection diversity. The 7-day Completion Time ensures that t~e plant will not be _operated in a degraded configuration for a lengthy time period.

G. If any requir~d ACTION of Conditions A, B, C, D, E or F cannot be met within the associated Completion Time, the plant mµst be brought to an OPERATIONAL CONDITION in which-the LCO does not apply. To achieve this status, the plant must be brought to at ,l.east HbT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and COLD SHUTDOWN within the riext 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. "'the allowed Completion Times are reasonable, based on operating experience, to perform the ACTIONS in an orderly manner and without ch~llenging plant systems.

SURVEILLANCE' REOUI REMENTS SR 4.4.3.1.a This SR is for the performance of a CHANNEL CHECK of the required primary containment atmospheri'C monitoring system. The check gives reasonable confidence that the channel is operattng properly.

SR 4.4.3.1.b This SR is for the performance of a CHANNEL FUNCTIONAL TEST of the required RCS leakage detection instrumentation. The test ensures that the monitors can perform their function in the desired manner. The test also verifies the alarm setpoint and relative accuracy of the instrument string, SR 4.4.3.1.c This SR is for the performance of a CH_ANNEL CALIBRATION of required leakage detection instrumentation channels. The calibration verifies the accuracy of the instrument string, including the i~struments located inside ~ontainment.

SR 4.4.3.1.d This SR provides a routine check of primary containment pressure and temperature for indirect evidence of RCS leakage.

REFERENCES

1. LGS UFSAR, Section 5.2.5.1.

2. Regulatory Gui de 1. 45, Revision O, "Reactor Cool ant Pressure Boundary Leakage Detection Systems," May 1973.

3. LGS UFSAR*, Section 5.2.5.2.1.3

4. LGS UFSAR, Section 5.2.5.2.1.4

5. LGS UFSAR, Section 5.2.5.2.1.1(2)

6. GEAP-5620, April 1968.

7. NUREG-75/067, October 1975.

8. LGS UFSAR, Section 5.2.5.6.

9. LGS UFSAR, Section 5.2.5.2.1.5 LIMERICK~ UNIT 2 B 3/4 4-3d Amendment~. 147 Associated with Amendment No: 167

REACTOR COOLANT SYSTEM 3/4.4.3.2 OPERATIONAL LEAKAGE ( __

The allowable leakage rates from the reactor coolant system have been based on the predicted and experimentally observed behavior of cracks in pipes. The normally expected background leakage due to equipment design and the detection capability of the instrumentation for determining system leakage was also considered. The evidence obtained from experiments suggests that for leakage somewhat greater than that specified for UNIDENTIFIED LEAKAGE the probability is small that the imperfection or crack associated with such leakage would grow rapidly. However, in all cases, if the leakage rates exceed the values specified or the leakage is located and known to be PRESSURE BOUNDARY LEAKAGE, the reactor will be shutdown to allow further investigation and corrective ac~ion. The limit of 2 gpm increase in UNIDENTIFIED LEAKAGE over a 24-hour period and the monitoring of drywell floor drain sump and drywell equipment drain tank flow rate at least once every eight (8) hours conforms with NRC staff positions specified in NRC Generic Lette*r 88-01, "NRC Position on IGSCC in BWR Austenitic Stainless Steel Piping," as revised by NRC Safety Evaluation dated March 6, 1990. The ACTION requirement for the 2 gpm increase in UNIDENTIFIED LEAKAGE limit ensures that such leakage is identified or a plant shutdown is initiated to allow further investigation and corrective action. Once identified, reactor operation may continue dependent upon the impact on total leakage.

The function of Reactor Coolant System Pressure Isolation Valves (PIVs) is to separate the high pressure Reactor Coolant System from an attached low pressure system.

The ACTION requirements for pressure isolation valves are used in conjunction with the system specifications for which PIVs are listed in The Technical Requirements Manual and with primary containment isolation valve requirements to ensure that plant operation is appropriately limited.

The Surveillance Requirements for the RCS pressure isolation valves provide added ~

assurance of valve integrity thereby reducing the probability of gross valve failure *.... **

and consequent intersystem LOCA. Leakage from the RCS pressure isolation valves is not included in any other allowable operational leakage specified in Section 3.4.3.2.

3/4.4.4 (Deleted) INFORMATION FROM THIS SECTION RELOCATED TO THE TRM LIMERICK - UNIT 2 B 3/4 4-3e Amendment No.~ * .J:..64., J.e, -+/-44 Associated with Amendment No. 167

.REACTOR COOLANT SYSTEM 3/4.4.5 SPECIFIC ACTIVITY The limitat ions on the specifi c activit y of the primary coolan t ensure line that the 2-hour thyroid and whole body doses resulti ng from a main steamexceed failure outside the containment during steady state operati on will not small fractio ns of the dose guideli nes of 10 CFR Part 100. The values for the limits on specif ic activit y represe nt interim limits based upon a parame tric evalua tion by the NRC of typical site locatio ns. These values are conserv ative in that specifi c site parameters, such as SITE BOUNDARY locatio n ~nd meteoro -

logical conditi ons, were not considered in this evaluat ion.

The ACTION statement permitt ing POWER OPERATION to continu e for limited 0.2 time periods with the primary coolan t's specifi c activit y greater than4 micro-microc urie per gram DOSE EQUIVALENT 1-131, but less than or equal to curies per gram DOSE EQUIVALENT 1-131, acconnno9ates possibl e iodine spiking action is phenomenon which may occur following changes in THERMAL fOWER. Thisication modified by a Note that permits the use of the provisi ons of Specif CONDITION 3.0.4.c . This allowance permits entry into the applica ble OPERATIONAL c activit y CS) while relying on the ACTION requirements. Operati on with specifi levels exceeding 0.2 microcurie per gram DOSE EQUIVAL ENT 1-131 but less than or equal to 4 microc uries per gram DOSE EQUIVAL ENT 1-131 must be restric ted since these activit y levels increas e the 2-hour thyroid dose at the SITE BOUNDAR Y following a pos~ula ted steam line rupture .

-- Closing the main steam line isolati on valves prevents the release ofment.

activit y to the environs should a steam line rupture occur outside adequat e assuran ce that excessi contain ve specifi c The surveil lance requirements provide ent time to

~ctivit y levels in the reactor coolan t will be detecte d in suffici take correc tive action.

3/4,4.6 PRESSURE/TEMPERATURE LIMITS All components in the reactor coolan t system are designed to withstas.nd the effects of cyclic loads due to system temperature and pressur e change trips, These cyclic loads are introduced by normal load transie nts, reactor load cycles and startup and shutdown operati ons. The various categor ies of used for design purposes are provided in Section 3.9 of the FSAR. During limited startup and shutdown, the rates of temperature and pressur e changes are with so that the maximum specifi ed heatup and cooldown rates are consis tent the design assumptions and satisfy the stress limits for cyclic operati on.

- I I TlAC"n T rv I IM TT ? R 1/4 4-4 Amendment No. 132

REACTOR COOLANT SYSTEM BASES ~

PRESSURE/TEMPERATURE LIMITS (Continued)

The operating limit curves of Figure 3.4.6.1-1 are derived from the fracture toughness requirements of 10 CFR 50 Appendix G and ASME Code Section XI, Appendix G. The curves are based on the RT~r and stress intensity factor information for the reactor vessel components. Fracture toughness limits and the basis for compliance are more fully discussed in FSAR Chapter 5, Para-graph 5.3.1.5, "Fracture Toughness."

The reactor vessel materials have been tested to determine their initial RTNor* The results of these tests are shown in Table B 3/4.4.6-1. Reactor operation and resultant fast neutron, E greater than 1 MeV, irradiation will cause an increase in the RT~r* Therefore, an adjusted reference temperature, based upon the fluence, nickel content and copper content of the material in question, can be predicted using Bases Figure B 3/4.4.6-1 and the recommenda-tions of Regulatory Guide 1.99, Revision 2, "Radiation Embrittlement of Reactor Vessel Materials." The pressure/temperature limit cµrve, Figure 3.4.6.1-1, curves A, Band C, includes an assumed shift in RT~1 for the conditions at 32 EFPY. In addition, an intermediate A curve was previously provided for 22 EFPY. However, the accumulated EFPY for Unit 2 will exceed 22 EFPY during Cycle 13 for Unit 2. Therefore, the A22 curve identified in Tech. Spec. Figure 3.4.6.1-1 (Pressure/Temperature Curves) can no longer be used when performing the Reactor Vessel Pressure Test for Unit 2. The A, Band C limit curves are predicted to be bounding for all areas of the RPV until 32 EFPY.

The pressure-temperature limit lines shown in Figures 3.4.6.1-1, curves C, (

and A, for reactor criticality and for inservice leak and hydrostatic testing have been provided to assure compliance with the minimum temperature requirements of Appendix G to 10 CFR Part 50 for reactor criticality and for inservice leak and hydrostatic testing.

LIMERICK - UNIT 2 B 3/4 4-5 Amendment No. ~.8Q.~.~.

L ECR 04-00575, Rev. 1

REACTOR COOLANT SYSTEM

) 314.4.7 MAIN STEAM LINE ISOLATION VALVES Double isol atio n valv es are provided on cont each of the main steam line s to from the ainment in case of a line break.

minimize the pote ntia l leak age pathsired to maintain the inte grit y of the Only one valve in each line is requ cont ainm ent, however, sing le fail ure ents cons ider atio ns requ ire that two valv es be based on the oper atin g hist ory of OPERABLE. The surv eilla nce requirem timearehas been sele cted to cont ain fiss ion this type valv e. The maximum clos ure uncovered following line breaks. The.

prod ucts and to ensure the core is not the assumptions in the safe ty anal yses to minimum clos ure time is con siste nt with prev ent pres sure surg es.

3/4.4.8 CDELETED) 3/4,4.9 RESIDUAL HEAT REMOVAL The RHR system is requ ired to remove deca y heat and sens ible heat in order to of tor cool ant. RHR shutdown cooling is (2) comprised main tain the temperature of the reac(2) loops. Each loop con sists of two motor four (4) subsystems which make two ciat ed piping and valv es. Both loop have s a driv en pumps, a heat exchanger, and asso n loop. Two (2) redundant, man ually common suct ion from the same reci rcul atio the RHR System can provide the requ ired been decay con trol led shutdown cool ing subsystems of harg es the reac tor coo lant ,*af ter it has heat removal cap abil ity. Each pump disc ecti ve heat exchangers, ta the reac tor via ctio the cooled by circ ulat ion through the resp reac tor via the low pres sure cool ant inje n

• ass ocia ted *rec ircu latio n loop or*t o thesfer heat to the RHR Serv ice Water System. The pathway. The RHR heat exchangers tran con trol led.

RHR shutdown cooling mode is manually con sists of an RHR pump, a heat An OPERABLE RHR shutdown cooling subsystemrols to ensure an OPERABLE flow path .

exchanger, valves, pipi ng, inst rum ents , ent and cont ition , the requ irem to maintain OPERABLE two (2) independent RHR In HOT SHUTDOWN cond subsystem cons ider ed OPERABLE must be shutdown cooling subsystems means that eachloop, i.e. , the "A" RHR heat exchanger with asso ciat ed with a diff eren t heat exhanger the "B" RHR heat exchanger with the "B" RHR the "A" RHR pump or the "C" RHR pump, illl.d.pend ent RHR shutdown cooling subsystems. Only pump or the "D" RHR pump are two (2) inde with each RHR heat exchanger loop is one Cl) of the two (2) RHR pumps asso ciat ed

• B 3/ 4 4-6 Amendment No. ~.-e-+/--,~,gg.,.i.J.J.,

LIMERICK - UNIT 2* Associated with Amendment 160

REACTOR COOLANT SYSTEM 3/4.4.9 RESIDUAL HEAT REMOVAL (Continued) (

required to be OPERABLE for that independent subsystem to be OPERABLE. During COLD SHUTDOWN and REFUELING conditions, however, the subsystems not only have a common suction source, but are allowed to have a common heat exchanger and common discharge piping. To meet the LCO of two (2) OPERABLE subsystems, both pumps in one (1) loop or one (1) pump in each of the two (2) loops must be OPERABLE. Since the piping and heat exchangers are passive components, that are assumed not to fail, they are allowed to be common to both subsystems. Additionally, each RHR shutdown cooling subsystem is considered OPERABLE if it can be manually aligned (remote or local) in the ~hutdown cooling mode for removal of decay heat. Operation (either continuous or intermittent) of one (1) 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.

Alternate decay heat removal methods are available to operators. These alternate methods of decay heat removal can be verified available either by calculation (which includes a review of component and system availability to verify that an alternate decay heat removal method is available) or by demonstration, and that a method of coolant mixing be operational. Decay heat removal capability by ambient losses can be considered in evaluating alternate decay heat removal capability.

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 non-condensable gas into the reactor vessel. This surveillance verifies that the RHR Shutdown Cooling System piping is sufficiently filled with water prior to initially placing the system in operation during reactor shutdown. The RHR Shutdown Cooling System is OPERABLE when it is sufficiently filled with water to ensure that it can reliably perform its intended function.

The RHR Shutdown Cooling System is a manually initiated mode of the RHR System whose use is typically preceded by system piping flushes that disturb both the RHR pump suction and discharge piping. RHR Shutdown Cooling System .is flushed and manually aligned for service using system operating procedures that ensure the RHR shutdown cooling suction and discharge flow paths are sufficiently filled with water. In the event that RHR Shutdown Cooling is required for emergency service, the system operating procedures that align and start the RHR System in shutdown cooling mode include the flexibility to eliminate piping flushes while maintaining minimum requirements to ensure that the suction and discharge flow paths are sufficiently filled with water. The RHR Shutdown Cooling System surveillance is met through the performance of the operating procedures that initially place the RHR shutdown cooling sub-system in service.

This surveillance requirement is modified by a Note allowing sufficient time (12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />) to align the RHR System for Shutdown Cooling operation after reactor dome pressure is less than the RHR cut-in permissive set point.

L LIMERICK - UNIT 2 B 3/4 4-6a Amendment No.~.

Associated with Amendment 178

L (

BASES TABLE B 3/4.4.6-1 REACTOR VESSEL TOUGHNESS*

LIMITING HEAT/SLAB MIN.UPPER BELTLINE WELD SEAM I.D. OR STARTING SHELF COMPONENT OR MAT'L TYPE ~EAT/LOT cu (%2 Ni ( %2 RTNDT {° F2 ~RTNDT **{°F2 ( LFT-LBS2 ART (°F}

Plate SA-533 Gr. B,CL. 1 B 3416-1 .14 .65 +40 +48 NA +122 Weld AB (Field Weld) 640892/ .09 1.0 -60 +58 NA +54 J424827AE NOTES:

• Based on 110% of original power.

• • These values are given only for the benefit of calculating the end-of-life (EOL/32 EFPY) RTNor NON-BELTLINE MT'L TYPE OR HEAT/SLAB OR HIGHEST STARTING COMPONENT WELD SEAM I.D, HEAT/LOT RTNDT Co F)

Top Shell Ring SA 533, Gr. B, CL. 1 C9800-2 -16 Bottom Head Dome C9245-2 +22 Bottom Head Torus II C9362-2 +28 Top Head Torus II C9646-2 -20 Top Head Flange SA-508, CL. 2 1238300 +10 Vessel Flange II 2L2058 +10 Feedwater Nozzle II 02029W 0 Weld Non-Beltline All -12 LPCI Nozzle*** SA-508, CL. 2 Q2Q33W -4 Closure Studs SA-540, Gr. B-24 All Meet requirements of 45 ft-lbs and 25 mils Lat. Exp. at +l0°F

• • • The design of the LPCI nozzles results in their experiencing an EOL fluence in excess of 10 17 N/Cm2 which predicts an EOL (32 EFPY) RTNoT of +35°F.

LIMERICK - UNIT 2 B 3/4 4-7 Amendment No. -el, 111

INTENTIONALLY LEFT BLANK C

l

1.2

-co I

0 1.0 X

>(lJ L

0.8 A

UJ N

E 0.6 u

C I (lJ u

C (lJ LL 0.4 C

0 a,

z 0.2 0.0 40 10 20 30 Servic e Life (Years *)

BASES FIGURE B 3/4.4. 6-1 FAST NEUTRON FLUENCE (E>l MeV) AT 1/4 T AS A FUNCTION OF SERVICE LIFE*

• _At 90% of Rated Therma l Power and 90% availa bility FEB 161995 2 B 3/4 4-8 .Amendment No. 51 LIMERICK - UNIT

C PAGE INTENTIONALLY LEFT BLANK L

3/4.5 EMERGENCY CORE COOLING SYSTEM B E

) 3/4.5.1 and 3/4.5.2 ECCS - OPERATING and SHUTDOWN The core spray system (CSS), together with the LPCI mode of the RHR system, is provided to assure that the core is adequately cooled following a loss-of-coolant accident and provides adequate core cooling capacity for all break sizes up to and including the double-ended reactor recirculatio n line break, and for.smaller breaks following depressuriza tion by the ADS. Management of gas voids is important to ECCS injection/sp ray subsystem OPERABILITY.

The CSS is a primary source of emergency core cooling after the reactor vessel is depressurize d and a source for flooding of the core in case of accidental .. draining.

The. surveillance requirements provide adequate assurance. that the CSS will be OPERABLE when required. Although all active components are testable and full flow can be demonstrated by recirculatio n through a test loop*during reactor operation, a complete functional test requires reactor shutdown.

The low pressure coolant injection CLPCI) mode of the RHR system is provided to assure that the core is adequately cooled following a loss-of-coolant accident. Four subsystems, each with one pump, prov~de adequate core flooding for all break sizes up to and including the double-ended reactor recirculatio n line break, and for small breaks following depressuriza tion by the ADS.

The surveillance requirements provide adequate assurance that the LPCI system will be OPERABLE when required. Although all active components are testable and full flow can be demonstrated by recirculatio n through a test loop during reactor operation, a complete functional test requires reactor shutdown.

• The high pressure coolant injection (HPCI) system is provided to assure that the reactor core is adequately cooled to limit fuel clad temperature in the event of a small break in the reactor coolant system and loss of coolant which does not result in rapid depressuriza tion of the reactor vessel. The HPCI system permits the reactor to be shut down while maintaining sufficient reactor vessel water level inventory until the vessel is depressurize d. The HCPI system continues to operate until reactor vessel pressure is below the pressure at which CSS operation or LPCI mode of the RHR system operation maintains core cooling.

The capacity of the system is selected to provide the required core cooling.

The HPCI pump is designed to deliver greater than or equal to 5600 gpm at reactor pressures between 1182 and 200 psig and is capable of delivering at least 50QO gpm between 1182 and 1205 psig. In the system's normal alignment, water from the condensate st*orage tank is used instead of injecting water from the suppression pool into the reactor, but no credit is taken in the safety analyses for the condensate storage tank water.

LIMERICK - UNIT 2 B 3/4 5-1 Amendment No. ~,.gg, ECR 00 00177, Associated with Amendment 178

EMERGENCY CORE COOLING SYSTEM ECCS - OPERATING and SHUTDOWN (Continued)

With the HPCI system inoperable, adequate core cooling is assured by the C

OPERABILITY of the redundant and diversified automatic depressurization system and both the CS and LPCI systems. In addition, the reactor core isolation cooling (RCIC) system, a system for which no credit is taken in the safety analysis, will automatically provide makeup at reactor operating pressures on a reactor low water level condition. The HPCI out-of-service period of 14 days is based on the demonstrated OPERABILITY of redundant and diversified low pressure core cooling systems and the RCIC system. The HPCI system, and one LPCI subsystem, and/or one CSS subsystem out-of-service period of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> ensures that sufficient ECCS, comprised of a minimum of one CSS subsystem, three LPCI subsystems, and all of the ADS will be available to 1) provide for safe shutdown of the facility, and 2) mitigat.e and control accident conditio.ns within the facility. A Note prohibits the application of Specification 3.0.4.b to an inoperable HPCI subsystem. There is an

• increased risk associated with entering an OPERATIONAL CONDITION or other specified condition in the Applicability with an inoperable HPCI subsystem and the provisions of Specification 3.0.4.b, which allow entry into an OPERATIONAL CONDITION or other specified condition in the Applicability with the Limiting Condition for Operatton not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.

The surveillance requirements provide adequate assurance that the HPCI system will be OPERABLE when required. Although all active components are testable and full flow can be demonstrated by recirculation thfough a test loop during reactor operation, a complete functional test with reactor vessel injection requires reactor shutdown. I 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 locations exceeds an acceptance criteria for gas volume at the suction or discharge of a pump), the Surveillance is not met. Accumulated gas should be eliminated or brought within the acceptance criteria limits.

LIMERICK - UNIT 2 B 3/4 5-2 Amendment No. 8/~/94 -1:-t-F, -e-8, ~ .

~ . -+/-4-7, Associated with Amendment No. 178

EMERGENCY CORE COOLING SYSTEM BASE J ECCS - OPERATING and SHUTDOWN (Continued)

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 same system flow path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representative subset 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.

Surveillance 4.5.1.a.l.b 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.

Upon failure of the HPCI system to function properly after a small break loss-of-coolant accident, the automatic depressurization system CADS) automa-tically causes selected safety/relief valves to open, depressurizing the reactor so that flow from the low pressure core cooling systems can enter the core in time to limit fuel cladding temperature to less than 2200°F. ADS is conserva-tively required to be OPERABLE whenever reactor vessel pressure exceeds 100 psig.

This pressure is substantially below that for which the low pressure core cool-ing systems can provide adequate core cooling for events requiring ADS.

ADS automatically controls five selected safety-relief valves. The safety analysis assumes all five are operable. The allowed out-of-service time for one valve for up to fourteen days is determined in a similar manner to other ECCS sub-system out-of-service time allowances.

Verification that ADS accumulator gas supply header pressure is ~90 psig ensures adequate gas pressure for reliable ADS operation. The accumulator on each ADS valve provides pneumatic pressure for valve actuation. The design pneumatic supply pressure requirements for the accumulator are such that, following a failure of the pneumatic supply to the accumulator at least two valve actuations can occur with the drywell ~t 70% of design pressure. 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-~90 psig is provided by the.PCIG supply.

LIMERICK - UNIT 2 B 3/4 5-3 Amendment No. g;~/-94 -1::-t-f., ~ * .J:..+/--e.,

-+/-*, -+/-4-7-,

Associated with Amendment No. 178

EMERGENCY CORE COOLING SYSTEM ECCS - OPERATING and SHUTDOWN (Continued) (

3/4.5.3 SUPPRESSION CHAMBER The suppression chamber is required to be OPERABLE as part of the ECCS to ensure that a sufficient supply of water is available to the HPCI, CS and LPCI systems in the event of a LOCA. This limit on suppression chamber minimum water volume ensures that sufficient water is available to permit recirculation cooling flow to the core. The OPERABILITY of the suppression chamber in OPERATIONAL CONDITION l, 2, or 3 is also required by Specification 3.6.2.1.

Repair work might require making the suppression chamber inoperable. This specification will permit those repairs to be made and at the same time give assurance that the irradiated fuel has an adequate cooling water supply when the suppression chamber must be made inoperable, including draining, in OPERATIONAL CONDITION 4 or 5.

In OPERATIONAL CONDITION 4 and 5 the suppression chamber m1n1mum required water volume is reduced because the reactor coolant is-maintained at or below 200°F. Since pressure suppression is not required below 212°F, the minimum water volume is based o~ NPSH, recirculation volume and vortex prevention plus a safety margin for conservatism.

(

( ___,

LIMERICK - UNIT 2 B 3/4 5-4 Amendment No*. +/-,a.,

Associated with Amendment No. 178

3/4.6 CONTAINMENT SYSTEMS

\ 3/4.6.1 PRIMARY CONTAINMENT

/

3/4.6.1.1 PRIMARY CONTAINMENT INTEGRITY PRIMARY CONTAINMENT INTEGRITY ensures that the release of radioactive mate-rials from the containment atmosphere will be restricted to those leakage paths and associated leak rates assumed in the safety analyses. This restriction, in conjunction with the leakage rate limitation, will limit the SITE BOUNDARY radiation. doses to within the limits of 10 CFR Part 100 during accident conditions.

3/4.6.1,2 PRIMARY CONTAINMENT LEAKAGE The limitations on primary containment leakage rates ensure that the total containment leakage volume will not exceed the value calculated in the safety analyses at the design basis LOCA maximum peak containment pressure of 44 psig, Pa. As I an added conservatism, the measured overall integrated leakage rate (Type A Test) is further limited to less than or equal to 0.75 La during performance of the periodic tests to account for possible degradation of the containment leakage barriers between leakage tests.

Operating experience with the main steam line isolation valves has indicated that degradation has occasionally occurred in the leak tightness of the valves; therefore the special requirement for testing these valves.

The surveillance testing for measuring leakage rates is consistent with the Pri~ary Containment Leakage Rate Testing Program.

3/4.6.1.3 PRIMARY* CONTAINMENT AIR LOCK The limitations on closure and leak rate for the primary containment air lock are required to meet the restrictions on PRIMARY CONTAINMENT INTEGRITY and the Primary Containment Leakage Rate Testing Program. Only one closed door in the air lock is required to maintain the integrity of the containment.

3/4.6.1.4 MSIV LEAKAGE ALTERNATE DRAIN PATHWAY Calculated doses resulting from the maximum leakage allowances for the main steamline isolation valves in the postulated LOCA situations will not exceed the criteria of 10 CFR Part 100 guidelines, provided the main steam lin~

system from the isolation valves up to and including the turbine condenser remains intact. Operating experience has indicated that degradation has occasionally occurred in the leak tightness of the MSIVs such that the specified leakage requirements have not always been continuously maintained. The requirement for the MSIV Leakage Alternate Drain Pathway serves to reduce the offsite dose.

LIMERICK - UNIT 2 B 3/4 6-1 Amendment No. -e-l-, ~. &+/--

ECR 11-00395

CONTAINMENT SYSTEMS 3/4.6.1,5 PRIMARY CONTAINMENT STRUCTURA~ INTEGRITY This limitation ensures that the structural integrity of the containment C

will be maintained comparable to the original design standards for the life of the unit. Structural integrity is required to ensure that the containment will withstand the maximum calculated pressure in the event of a LOCA. A visual inspection in accordance with the Primary Containment Leakage Rate Testing Program is sufficient to demonstrate this capability.

3/4.6.1,6 PRYWELL AND SUPPRESSION CHAMBER INTERNAL PRESSURE

,. The limit~tions on drywell and suppression. chamber internal pressure ensure that the calculated containment peak pressure does not exceed the design pressure of 55 psig during LOCA conditions or that the external pressure. differ-ential does not exceed the design maximum external pressure differential of 5.-0 psid. The limit of - 1.0 to+ 2.0 psig for initial containment pressure will limit the total pressure to~ 44 psig which is less than the design pressure and is consistent with the safety analysis.

3/4.6,1,Z PRYWE~L AVERAGE AIR TEMeEBATURE The limitation on drywell average air temperature ensures that the con-tainment peak air temperature does not exceed the design temperature of 340°F during steam line br~ak conditions and is consistent with the safety analysis.

3/4,6.1,8 DRYWELL ANO SUPPRESSION CHAMB~B PURGE SYSTEM

(

The drywell and suppression chamber purge supply and exhaust isolation valves are required to be closed during plant operation except as required for inerting, deinerting, pressure control, ALARA or air quality considerations for personnel entry, or Surveillances that require the valves to be open. Limiting the use of the drywell and suppression chamber purge system to specific criteria is imposed to protect the integrity of the SGTS filters. Analysis indicates that should a LOCA occur while this *pathway 1s being utilized, the associated pressure surge through the (18 or 24") purge lines will adversely affect the integrity of SGTS. This condition is not imposed on the 1and21nch valves used for pressure control since a surge through these lines does not threateri the operability of SGTS.

Surveillance requirement 4.6.1.8 ensures that the primary containment purge valves are closed as required or, if open, open for an allowable reason. If a purge valve is open in violation of this SR, the valve is considered inoperable.

The SR is modified by a Note stating that primary containment purge valves are only required to be closed in OPERATIONAL CONDITIONS 1, 2 and 3. The SR is also modified by a Note stating that the SR is not required to be met when the purge _valves are open for the stated reasons. The Note states that these valves may be opened for inerting, deinerting, pressure control, ALARA or air quality considerations for personnel entry, or Surveillances that require the valves to be open. The 18 or 24 inch purge valves are capable of closing in the environment following a LOCA. Therefore, these valves are allowed to be open for limited periods of time.

(__

LIMERICK - UNIT 2 8 3/4 6-2 Amendment No. i.,+7,S..,~,147

CONTAINMENT SYSTEMS

\ 3/4.6.2 DEPRESSURIZATION SYSTEMS The specifica tions of this section ensure*th at the primary containment pressure will not exceed the design pressure of 55 psig during primary system blowdown from full operating pressure. Management of gas voids is important to Suppression Pool Cooling/Spray Subsystem OPERABILITY.

The suppressio n chamber water provides the heat sink for the reactor coolant system energy release following a postulated rupture of the system. The suppressio n chamber water volume must absorb the associated decay and structural sensible heat released during reactor coolant system blowdown from rated condition s.

Since all of the gases in the drywell are purged into the suppression chamber air space during a loss-of-co olant accident, the pressure of the suppression chamber air space must not exceed 55 psig. The design volume of the suppression chamber, water and a~r, was obtained by considerin g that the total volume of reactor coolant is discharged to the suppression chamber and that the drywell *volume is purged to the suppressio n chamber.

Using the minimum or maximum water volumes given in this specifica tion, suppressio n pool pressure during the design basis accident is below the design pressure. Maximum water volume of 134,600 ft 3 results in a downcomer submergence of 12'3" and the minimum volume of 122,120 ft 3 results in a submergence approximately 2'3" less. The majority of the Bodega tests were run with a submerged length of*4 feet and with complete condensati on. Thus, with respect to the downcomer submergence,

• this specifica tion is ~dequate. The maximum temperatu re at the end of the blowdown tested during the Humboldt Bay and Bodega Bay tests was 170°F and this is conservat ively taken to be the limit for complete condensati on of the reactor coolant, although condensati on would occur for temperatu re above 170°F.

Should it be necessary to make the suppression chamber inoperable , this shall only be done as specified in Specifica tion 3.5.3.

Under full power operating condition s, blowdown through safety/re lief valves assuming an initial suppression chamber water temperature of 95°F results in a bulk water temperatu re of approximately 140°F immediately following blowdown which is below the 190°F bulk temperature limit used for complete condensation via T-quencher devices. At this temperature and atmospheric pressure, the available NPSH exceeds that required by both the RHR and core spray pumps, thus there is no dependency on containment overpressu re during the accident injection phase. If both RHR loops are used for containment cooling, there is no dependency on containment overpressu re for post-LOCA operation s.

LIMERICK - UNIT 2 B 3/4 6-3 Amendment No. ~.~,-e-+/-,

Associated with Amendment 178

CONTAINMENT SYSTEMS 3/4.6.2 DEPRESSURIZATION SYSTEMS (Continued)

C RHR Suppression Pool Cooling/Spray subsystem p1p1ng 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 subsystems and may also prevent water hammer and pump cavitatton.

Selection of RHR Suppression Pool Cooling/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 RHR Suppression Pool Cooling/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 locations exceeds an acceptance criteria for gas volume at the suction or discharge of a pump), the Surveillance is not met.

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

RHR Suppression Pool Cooling/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 same system flow path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representative subset of susceptible locations. Monitoring may not be pract~cal 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.

One of the surveillance requirements for the suppression pool cooling (SPC) mode of the RHR system is to demonstrate that each RHR pump develops a flow rate 3

10,000 gpm while operating in the SPC mode with flow through the heat exchanger and its associated closed bypass valve, ensuring that pump performance has not degraded during the cycle and that the flow path is operable. This test confirms one point on the pump design curve and is indicative of overall performance. Such inservice inspections confirm component operability, trend performance and detect incipient failures by indicating abnormal performance. The RHR heat exchanger bypass valve is used for adjusting flow through the heat exchanger, and is not .designed to be a tight shut-off valve. With the bypass valve closed, a portion of the total flow still travels through the bypass, which LIMERICK - UNIT 2 B 3/4 6-3a Amendment No.~.~.

Associated with Amendment 178

CONTAINMENT SYSTEMS

\

I 3/4.6.2 DEPRESSURIZATION SYSTEMS (Continued) can affect overall heat transfer. However, no heat transfer performance requirement of the heat exchanger is intended by the current Technical Specificatio n surveillance requirement. This is confirmed by the lack of any flow requirement for the RHRSW system in Technical Specificatio ns Section 3/4.7.1.

Verifying an RHR flowrate through the heat exchanger does not demonstrate heat removal capability in the absence of a requirement for RHRSW flow. LGS does perform heat transfer testing of the RHR heat exchangers as part of its response to Generic Letter 89-13, which verified the commitment to meet the requirements of GDC 46.

Experimental data indicate that excessive steam condensing loads can be avoided if the peak local temperature of the suppression pool is maintained below 200°F during any period of relief valve operation for T-quencher devices.

Specificatio ns have been placed on the envelope of reacto~ operating conditions so that the reactor can be depressurize d in a timely manner to avoid the regime of potentially high suppression chamber loadings.

Because of the large volume and thermal capacity of the suppression pool, the volume and temperature normally changes very slowly and monitoring these parameters daily is sufficient to establish any temperature trends. By requiring the suppression pool temperature to pe frequently recorded during periods of significant heat addition, the temperature trends will be closely followed so J that appropriate action can be taken.

In addition to the limits on temperature of the suppression chamber pool water, operating procedures define the action to be taken in the event a safety-relief valve inadvertentl y opens or sticks open. As a minimum this action shall include: (1) use of all available means to close the valve, (2) initiate suppres-sion pool water cooling, (3) initiate reactor shutdown, and (4) if other safety-relief valves are used to depressurize the reactor, their discharge shall be separated from that of the stuck-open safety/relie f valve to assure mixing and uniformity of energy insertion to the pool.

During a LOCA, potential leak paths between the drywell and suppression chamber airspace could result in excessive containment pressures, since the steam flow into the airspace would bypass the heat sink capabilities of the chamber. Potential sources of bypass leakage are the suppression chamber-to-drywell vacuum breakers (VBs),

penetrations in the diaphragm floor, and cracks in the diaphragm floor and/or liner plate and downcomers located in the suppression chamber airspace. The containment pressure response to the postulated bypass leakage can be mitigated by manually actuating the suppre?-5ion chamber sprays. An analysis was performed for a design bypass leakage area of A/~k equal to 0.0500 ft 2 to verify that the operator has sufficient time to initiate the sprays prior to exceeding the containment design pressure of 55 psig. The limit of 10% of the design value of 0.0500 ft 2 ensures that the design basis for the steam bypass analysis is met LIMERICK - UNIT 2 B 3/4 6-3b Amendment No. ~.-d-l-,

Associated with Amendment 178

-i

c

-~

CONTAINMENT SYSTEMS BASES DEPRESSURIZATION SYSTEMS (Continued)

The drywell-to-s uppression chamber bypass test at a differential pressure of at least 4.0 psi verifies the overall bypass leakage area for simulated LOCA conditions is less than the specified limit. For those outages where the drywell-to-s uppression chamber bypass leakage test in not conducted, the VB leakage test verifies that the VB leakage area is less than the bypass limit, with a 76% margin to the bypass limit to accommodate the remaining potential leakage area through the passive structural components. Previous drywell-to-s uppression chamber bypass test data indicates that the bypass leakage through the passive structural components will be much less than the 76% margin. The VB leakage limit, combined with the negligible passive structural leakage area, ensures that the drywell-to-suppression chamber bypass leakage limit is met for those outages for which the drywell-to-s uppression chamber bypass test is not scheduled.

3/4.6.3 PRIMARY CONTAINMENT ISOLATION VALVES The OPERABILITY of the primary containment isolation valves ensures that the containment atmosphere will be isolated from the outside environment in the event of a release of radioactive material to the containment atmosphere or pressurizati on of the containment and is consistent with the requirements of GDC 54 through 57 of Appendix A of 10 CFR Part 50. Containment isolation within the time limits specified for those isolation valves designed to close automaticall y ensures that the release of radioactive material to the environ-ment will be consistent with the assumptions used in the analyses for a LOCA.

The scram discharge volume vent and drain valves serve a dual function, one of which is primary containment isolation. Since the other safety functions of the scram discharge volume vent and drain valves would not be available if the normal PCIV

) actions were taken, actions are provided to direct the user to the scram discharge volume vent and drain operability requirements contained in Specificatio n 3.1.3.1.

However, since the scram discharge volume vent and drain valves are PCIVs, the Surveillance Requirements of Specificatio n 4.6.3 still apply to these valves.

The opening of a containment isolation valve that was locked or sealed closed to satisfy Technical Specificatio n 3.6.3 Action statements, may be reopened on an intermitten t basis under administrati ve controls. These controls consist of stationing a dedicated individual at the controls of the valve, who is in continuous communication with the control room. In this way, the penetration can be rapidly isolated when a need for primary containment isolation is indicated.

Primary containment isolation valves governed by this Technical Specificatio n are identified in Table 3.6.3-1 of the TRM.

This Surveillance Requirement requires a demonstration that a representati ve sample of reactor instrument line excess flow check valves (EFCVs) is OPERABLE by verifying that the valve actuates to the isolation position on a simulated instrument line break signal. The representati ve sample consists of an approximately equal number of EFCVs, such that each EFCV is tested in accordance with the Surveillance Frequency I Control Program. In addition, the EFCVs in the sample are representati ve of the various plant configuratio ns, models, sizes, and operating environments. This ensures that any potentially common problem with a specific type or application of EFCV is detected at the earliest possible time. This Surveillance Requirement provides assurance that the instrumenta tion line EFCVs will perform so that predicted radiological consequences will not be exceeded during a postulated instrument line break event. Furthermore, any EFCV failures will be evaluated to determine if additional testing in the test interval is warranted to ensure overall reliability is maintained. Operating experience has demonstrated that these components are highly reliable and that failures to isolate are very infrequent. Therefore, testing of a representati ve sample was concluded to be acceptable from a reliability standpoint.

For some EFCVs, this Surveillance can be performed with the reactor at power.

LIMERICK - UNIT 2 B 3/4 6-4 Amendment No. ~.JJ.,-+/-07,-l-10,-l-J.l,147

CONTAINMENT SYSTEMS BASES 3/4.6.4 VACUUM RELIEF c-Vacuum relief valves are provided to equalize the pressure between the suppression chamber and drywall. This system will maintain the structural integrity of the primary containment under conditions of large differential pressures.

The vacuum breakers between the suppression chamber and the drywall must not be inoperable in the open position since this would allow bypassing of the suppression pool in case of an accident. Two pairs of valves are required to protect containment structural integrity. There are four pairs of valves (three to provide minimum redundancy) so that operation may continue for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> with no more than two pairs of vacuum breakers inoperable* in the closed position.

Each vacuum breaker valve's position indication system is of great enough sensitivity to ensure that the maximum steam bypass leakage coefficient of h

..Jk = o. os fe for the vacuum relief system (assuming one valve fully open) will not be exceeded.

C

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LIMERICK - UNIT 2 B 3/4 6-4a Amendment No. 110 I*

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• 0 0

.:.Frequency.** tcin.troi*)'rogf atf;-_' iilo-ng***:w.i t'h::tli*e i:sur.ve111 ahce of: ttie. *.do'o*r,s >..' ha:tche's-; .da-mpeTS a*od* .v.alv:e~ ;:,:>is,, adequate:- to;:e:nS*ure* thaf* .tt:r~re<are *n:cl ,V.io 1"citi on,s *.o*f the'* firt:egtitf of: .

the *s~c:b*no~rry, *co11ta.fnmenL..:* . * .* . .. * . ' .. * . ***.. *. *..* .. * .. . ' . * ..

• • • .*  :. .-:\'. .. * ..

. .*rne. OJi[R'ABJ bJjy tif the ~~actor .:enc.l'o~ute r~.~-i rtul at., o,n: sys,tein atid .the: s*t*~*n.dby gas treatme:nt' sfste.tns -~fris1i't1:fs:* t~Ii't suffi cl':ent iodfoe: remova f cap~a:lii'l-ity_. w.i 11 * ** :*: * . . :

be available- ; n-thEf ::e.\/.ent,:of a: LOCA*~,.- . The: reductibn>i ii*.coiltai ilment iodine: inventory:.: *.

redu~es**tlre- result-J,ng,,.S fTE/ BOUNDARY'**and. Coritrok *.Room* r:adi at i o,n\ tjQ.s.e::S, ass~ci ate.o 'with *

• coritalnm.e.i'J:t.* l'epkag~-~- .* *Thi; ':op*e..ratf:ontof *tnese>sysJerns and** re;s-u 1t'aht:. i od tne* removal'*. -

• . ca*pa:cdcy., aJ,e*.*eph.sJ s:tertt'. *w.i t:tt<t,h.¢i:as-sumpt1o'ri:si*us*ed-::;rh *,t.he:. lOCA arialyil ~ ~>: . Pto\/fsi Ons.-: *.

n~*ve, ;freeh iiilad*e* .f~f ConHnt1.ciu:sly{ p:Urg,e :. the. Jfl te:r. .-ple'.hiJlli.s *with*:: i tls:frument at r** when:. th~:* ..

. fi1 ter.s/*a.re, not*. tn use *to:*prevent::.:*bulldr.ip):rf.' rrio\sture::on. :the- ads*.o.rbers* .. and* the,. HE.PA .

• fi*lter~.*:. '.* * * * .* ** ** * * * * , * .. * * * *

• A;.a.: rfsuJt of:-.tne Alt.ernatJ~e* Sour'ce -iiri:fr:.(AS-JJ p.roje*~t~ -s*econdary;*

coritainment, lnt-.egri ty. O'f.' the::.refue*l i rig. area* is not required:. during: ce;rtai n: ..

, j . * : 'condHibn.s:: \vhen handi i'hg if;ra.di a_teddtiel

• or dur.inR* CORE-.. A~TERATION!i ~nEl*"~l i'<;jnrtre.nt*

\<~< * * **::of*the:*:st}rric:ibY, :Gas; Tr.eatme11't. System t-0'. the*ne*fu~ffng: ~rea, . *rs-:~-ribt*:_reqtlheiJ; :n,e;:_. * .

• con:i..r:o'f io:om: doS:e *a*n:al;Y,$:i:s .-*..f.or.. the>Fuel 'ffa:nd1 irtg 'Aceident: (FHA,,). *i s'. _:bas~d *cm o. ; . *

. urrf'fiiered.:releai;eS:fronF trye;- stiutfr *Stack\irid' t:her~fbre ,:. d.o:es/ noi. requffe" the.**.*** ,.

St:andby:**Gas: Treatment.System-to :be, aligned,: tote.the r.~fuel i'i:ig:\r.~g;.: .. **::. . .: . < .

• 0 T * *

• 0 0 ,* * * * ,> 0 ***

How:e\ie-r . ,: wb.e.1:r*n~*rtdi'i i,g.* RECENTLY* TRRAbIATED: FUEL or duri n~(ciperations with *a p.otential_.fqr* draining the' rea..ctor vessel w.ith the. vessel.head* r*emoved ,n,d -i'_uel-in

. the:. ve:ssel *,. '~'eco.r:Jdary :co.ntai*nment i:nbegr}t.y.- o(:the:. r.*efuel i ng, )rea ls. r.eqtii red 'and ai i t:nntent. of* the Standby &.as Treatment --s}stem ~o the r-efuel iri'g: a-'re.a i_s required.*

The AST fuel ha:tidliri.g* anal.ysi.s does not include:. an acci-dent- involving -~~CENTLY *

. IRRADtATED FUEL. or* ~n accid.ent 1nv'9J vtng drafoi_ng, the reactor ve*ss_eL . ** . .

• Tfie* Staritlb:y

• Ga-i* t.reatrrie.nt. *system, is.. required. to* be-. OPERABLE whe*n ha.ndl. i ng.. _.

itridiated; fuel i:*_handiirrg. RE,CENTlY IRRAD1ATE'0-.FU.EL,:.durfn<J Cb.RE. ALTERATfo-N"s*a'rid.

dt..rr*1ng aperaH:o-r1~s.with' a* pot.entialto dratri:the vessel: withthe*:vessel hea-ct.

• removed and *fuel .fr\ t:he.vess:e-L Fuel H'anoling Accident *release:s.* fronr th:e.*Narth Stack- rriµst; be f11 tered tht*oug:h. the Standby* Gas. rreatrn'ent Sy-stein to mai-ntai n controi *roo.m.*doses with:in regUlatory limits:;* The OPERABILITY *of the S-ta:ndby Gas Treatmen.t *system as.sures that rel eases, jf mild.e.. through the No.rth Stack; are

'fi 1tered p-ri:or to .r.e l ea-.se ..

, I i-.~-*

LIM~RlCK - WHT 2 Arri'er'idment No. J4,M,g.&,J.4.e:,.W.,

ECR LG 09-000.52

CONTAINMENT SYSTEMS SECONDARY CONTAINMENT (Continued)

Surveillances 4.6.5.1.1. a and 4.6.5.1.2 .a are each modified by a footnote( *) (

which states the surveillan ce is not required to be met for up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> if an analysis demonstrates that one standby gas treatment subsystem remains capable of establishi ng the required secondary containment vacuum. Use of the footnote is expected to be infrequent but may be necessitat ed by situations in which secondary containment vacuum may be less than the required containment vacuum, such as, but not limited to, wind gusts or failure or change of operating normal ventilatio n subsystems. These conditions do not indicate any change in the leak tightness of the secondary containment boundary. The analysis should consider the actual conditions (equipment configuration, temperature, atmospheric pressure, wind condition s, measured secondary containment vacuum, etc.) to determine whether, if an accident requiring secondary containment to be OPERABLE were to occur, one train of standby gas treatment could establish the assumed secondary containment vacuum within the time assumed in the accident analysis. If so, the surveillan ce may be considered met for a period up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The 4-hour limit is based on the expected short duration of the situations when the footnote would be applied.

Surveillances 4.6.5.1.1. b.2 and 4.6.5.1.2 .b.2 require verifying that one secondary containment personnel access door in each access opening is closed which provides adequate assurance that exfiltrati on from the secondary containment will not occur. An access opening contains at least one inner and one outer door. The intent is to not breach the secondary containment, which is achieved by maintaining the inner or outer personnel access door closed. Surveillances 4.6.5.1.1. b.2 and 4.6.5.1.2. b.2 provide an allowance for brief, inadverte nt, simultaneous openings of redundant secondary containment personnel access doors for normal entry and exit conditions. (

Although the safety analyses assumes that the reactor enclosure secondary containment draw down time will take 930 seconds, these surveillan ce require-ments specify a draw down time of 916 seconds. This 14 second difference is due to the diesel generator starting and sequence loading delays which is not part of this surveillan ce requirement.

The reactor enclosure secondary containment draw down time analyses assumes a starting point of 0.25 inch of vacuum water gauge and worst case SGTS dirty filter flow rate of 2800 cfm. The surveillan ce requirements satisfy this as-sumption by starting the drawdown from ambient conditions and connecting the adjacent reactor enclosure and refueling area to the SGTS to split the exhaust flow between the three zones and verifying a minimum flow rate of 2800 cfm from the test zone. This simulates the worst case flow alignment and verifies ade-quate flow is available to drawdown the test zone within the required time.

The Technical Specificat ion Surveillance Requirement 4.6.5.3.b. 3 is intended to be a multi-zone air balance verificati on without isolating any test zone.

The SGTS is common to Unit 1 and 2 and consists of two independent subsystems. The power supplies for the common portions of the subsystems are from Unit 1 safeguard busses, therefore the inoperabi lity of these Unit 1 supplies are addressed in the SGTS ACTION statements in order to ensure adequate onsite power sources to SGTS for its Unit 2 function during a loss of offsite power event. The allowable out of service times are consistent with those in the Unit 1 Technical Specificat ions for SGTS and AC electrical power supply out of service condition combinations. L LIMERICK - UNIT 2 B 3/4 6-Sa Amendment No. J-4,9-l-,Se,+46,-147, EGR LG 09 00052, Associated with Amendme nt~. 192

CONTAINMENT SYSTEMS IASES

\

1$ECDNQABJ CQNIAI"'ENJ (Cont111ued)

The SSTS fans are sized far three zones and therefore, when al19nud ta a single zane or ~IIID z1111es, will have excess capacity to 11111re quickly dralldown ttle affected Zanes. There 1s no 11Ui11m flaw 11ait to 1ncl1v1dual zanes or pa;~s af zones and th* air balance and drawdolm t111e ara verified when all three zanes are r:annec:tecl ta 'the SGTS.

Tbe tllree zone air balance verificatian and draa.dltlWII test will be done aft.er illl7 major syst* alterat.ion~ vhich is any mdiffcat1an ldltcll Will h*ve an e~fect an the SITS flawrate such that the ability of the SGTS to dra.d1111n the reactor enclosure to greater- than ar equl to G.25 inch of v1cu1111 water gage tn less than ar e11ual to 916 seconds could be affected.

Th* field tests far bypass leak11e across the S&TS charcoal adsorbe~ and HEPA f;ltar banks are perfol"'lled *t a fl* rate of 5764 *- lOS cfa. The laboratory analysis perfol"lllld on the SCTS carbon samples will be tested at a velocity of i6 fpa based on the 1yst* residence tt11111.

The SGTS f11ter tra;n pressure drap is a function af air flow rate and f;lter conditions. Surveill..-c e testing ts performed using either the SGTS ar drY'll!ll purge fans ta pra~tde operating canvenience.

Each reactor enclasure secandary cantai1111&nt zone and rafuel;ng area secDndary can1:ainmnt zone is tested independently to Yerify the design leak tightness. A design leak tightness af 2500 cfa or less far each reactor enclosure and 11, cfm or less far the refueling area at ii 0.25 ;qch af va~uum b.ater gage will ensure that conta;nment integrity is ma;ntained at an acceptable

'-"level ff all zones ara connected to the SGTS at the siilllle tiae_

The ReiilCtor Enclosure Secondary ContaiMll!nt Autamatic_I sola~ion Vi!lves and Refueling Area Secondary Ca"taiffllll!n~ Autamatic Jsalat;an Valves can be found in the UFSAR.

. The past-LDCA affstte dose analys;s assumes a reactor enclosure secondary cantailllll!ft~ post-cir~ dawn leakage rate af zsao cfm and certain post-accide nt 1/Q values. IRlt1e the post-accide nt X/Q values repPl!sant a stat;st;cal 1nter-pretat1an of historical metearalngi cal data. the highest ground level w;nc1 speed which can be associated with these values ;s 7 mph (Pa.squill-G ifforct stability Class C for a ground level release). Therefore, the surveillanc e requ;reaent assures that the reactar enclosure secandary containment is verified under aeteoro1ag1cA1 canditians consistent with the assumpt;ans utilized in the design basis .aalysis. Re1ctor Enclosure Secondary Cantail'llll!at leakage tests that are successfull y perforaed at *ind speeds in ezcess af 7 mph 110uld also satisfy the leak rate surveillanc e requirement s, since it shows caap11ance with aore*conser vat1ve test c~nditians.

~LIMERICK - UNIT 2 I 3/' 6-6 ArilEP due.at. N:I. !J,.,, /JJ._ .eJ FEB 1 8 1997

CONTAINMENT SYSTEMS

~..._..,,.

..,._,,-.,,._.. __~~.,*-== *=T'~C=~= =-=~--=== ====--

3/4.6.6 PRIMARY CONTAINMENT ATMOSPHERE CONTROL (

The primary containment atmospheric mixing system is provided to ensure adequate mixing of the containment atmosphere to prevent localized accumulations of hydrogen and oxygen from exceeding the lower flammability limit during post-LOCA conditions.

All nuclear reactors must be designed to withstand events that generate hydrogen either due to the zirconium metal water reaction in the core or due to radiolysis. The primary method to control hydrogen is to inert the primary containment. With the primary containment inert, that is, oxygen concentration <4.0 volume percent (v/o), a combustible mixture cannot be present in the primary containment for any hydrogen concentration. The capability to inert the primary containment and maintain oxygen <4.0 v/o works together with Drywell Hydrogen Mixing System to.. provide redundant and diverse methods to mitigate events that produce hydrogen.

l

\

.;,.

(

LIMERICK - UNIT 2 B 3/4 6-7 Amendment No.

[CR QQ QQ1J2, 135

3/4.7 PLANT SYSTEMS 3/4.7.1 SERVICE WATER SYSTEMS - COMMON SYSTEMS The OPERABILITY of the service water systems ensures that sufficient cooling capacity is available for continued operation of safety-related equipment during normal and accident conditions. The redundant cooling capacity of these systems, assuming a single failure, is consistent with the assumptions used in the accident conditions within acceptable limits.

The RHRSW and ESW systems are common to Units 1 and 2 and consist of two independent subsystems each with two pumps. One pump per subsystem (loop) is powered from a Unit 1 safeguard bus and the other pump is powered from a Unit 2 safeguard bus. In order to ensure adequate onsite power sources to the systems during a loss of offsite power event, the inoperability of these supplies are restricted in system ACTION statements.

RHRSW is a manually operated system used for core and containment heat removal. Each of two RHRSW subsystems has one heat exchanger per unit. Each RHRSW pump provides adequate cooling for one RHR heat exchanger. By limiting operation with less than three OPERABLE RHRSW pumps with OPERABLE Diesel Generators, each unit is ensured adequate heat removal capability for the design scenario of LOCA/LOOP on one unit and simultaneous safe shutdown of the other unit.

Each ESW pump provides adequate flow to the cooling loads in its associated loop .. With only two divisions of power required for LOCA mitigation of one unit and one division of power required for safe shutdown of the other unit, one ESW pump provides sufficient capacity to fulfill design requirements. ESW

) pumps are automatically started upon start of the associated Diesel Generators.

Therefore, the allowable out of service times for OPERABLE ESW pumps and their associated Diesel Generators is limited to ensure adequate cooling during a loss of offsite power event.

3/4.7.2 CONTROL ROOM EMERGENCY FRESH AIR SUPPLY SYSTEM - COMMON SYSTEM The OPERABILITY of the control room emergency fresh air supply system ensures that the control room will remain habitable for occupants during and following an uncontrolled release of radioactivity, hazardous chemicals, or smoke.

Constant purge of the system at 1 cfm is sufficient to reduce the buildup of moisture on the adsorbers and HEPA filters. The OPERABILITY of this system in conjunction with control room de~ign provisions is based on limiting the radiation exposur~ to personnel occupying the control room to 5 rem or less Total Effective Dose Equivalent. This limitation is consistent with the requirements of 10 CFR Part 50.67, Accident Source Term.

Since the Control Room Emergency Fresh Air Supply System is not credited for filtration in OPERATIONAL CONDITIONS 4 and 5, applicability to 4 and 5 is only required to support the Chlorine and Toxic Gas design basis isolation requirements.

The CREFAS is common to Units 1 and 2 and consists of two independent subsystems. The power supplies for the system are from Unit 1 Safeguard busses, therefore, the inoperability of these Unit 1 supplies are addressed in the CREFAS ACTION statements in order to ensure adequate onsite power sources to CREFAS during a loss of offsite power event. The allowable out of service LIMERICK - UNIT 2 B 3/4 7-1 Amendment No. -+/-4&, 149

PLANT SYSTEMS C

CONTROL ROOM EMERGENCY FRESH AIR SUPPLY SYSTEM - COMMON SYSTEM (Continued) times are consistent with those in the Unit 1 Technical Specifications for CREFAS and AC electrical power supplj out of service condition combinations.

The Control Room Envelope (CRE) is the area within the confines of the CRE boundary that contains the spaces that control room occupants inhabit to control the unit during normal and accident conditions. This area encompasses the control room, and other noncritical areas including adjacent support offices, toilet and utility rooms. The CRE is protected during normal operation, natural events, and accident conditions. The CRE boundary is the combination of walls, floor, ceiling, ducting, valves, doors, penetrations and equipment that physically form the CRE. The OPERABILITY of the CRE boundary must be maintained to ensure that the inleakage of unfiltered air into the CRE will not exceed the inleakage assumed in the licensing basis analysis of design basis accident (OBA) consequences to CRE occupants. The CRE and its bo~ndary are defined in the Control Room Envelope Habitability Program.

In addition, the CREFAS System provides protection from radiation, smoke and hazardous chemicals to the CRE occupants. The analysis of hazardous chemical releases demonstrates that the toxicity limits are not exceeded in the CRE following a hazardous chemical release (Ref. 1). The evaluation of a smoke challenge demonstrates that it will not result in the inability of the CRE occupants to control the reactor either from the control room or from the remote shutdown panels (Ref. 2). (

In order for the CREFAS subsystems to be considered OPERABLE, the CRE boundary must be maintained such that the CRE occupant dose from a large radioactive release does not exceed the calculated dose in the licensing basis consequence analyses for DBAs, and that CRE occupants are protected from hazardous chemicals and smoke.

The LCO is modified by a Note allowing the CRE boundary to be opened intermittently under administrative controls. This Note only applies to openings 1n the CRE boundary that can be rapidly restored to the design condition, such as doors, hatches, floor plugs, and access panels. For entry and exit through doors, the administrative control of the opening is performed by the person(s) entering or exiting the area. For other openings, these controls should be proceduralized and consist of stationing a dedicated individual at the opening who is in continuous communication with the operators in the CRE. This individual will have a method to rapidly close the opening and to restore the CRE boundary to a condition equivalent to the design condition when a need for CRE isolation is indicated.

If the unfiltered inleakage of potentially contaminated air past the CRE boundary and into the CRE can result in CRE occupant radiological dose greater than the calculated dose of the licensing basis analyses of OBA consequences (allowed to be up to 5 rem TEDE), or inadequate protection of CRE occupants from hazardous chemicals or smoke, the CRE boundary is inoperable. Actions must be taken to restore an OPERABLE CRE boundary within 90 days. (

LIMERICK - UNIT 2 B 3/4 7-la Amendment No.~. 149

PLANT SYSTEMS

) (Continued)

CONTROL ROOM EMERGENCY FRESH AIR SUPPLY SYSTEM - COMMON SYSTEM action During the period that the CRE boundary is considered inope rable, the effec t s to lessen must be initia ted immediately to* implement mitigating action or chemical event or on CRE occupants from the poten tial hazards of a radiol ogica l to verify that in a challe nge from smoke. Actions must be taken within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> occupant the event of a OBA, the mitig ating action s will ensure that ofCREthe licens ing basis radiol ogica l exposures will not exceed the ca~culated dose ted from hazardous analy ses of OBA consequences, and that CRE occupants are protec that are taken to chemicals and smoke. These mitig ating action s (i.e., action s be preplanned for offse t the consequences of the inoperable CRE boundary) should er entry is implementation upon entry into the condi tion, regard less of wheth reasonable based on intent ional or unint ention al. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Time is , and the use of the low proba bility of a* OBA occurring during this time period based on the mitig ating action s. The 90 day Completion Time is reasonable of CRE occupants determ inatio n that the mitig ating action s will ensure prote ctionoccupants will have within analyzed limits while limiti ng the proba bility that CRE abilit y to to implement prote ctive measures t~at may adversely affec t their in the event of a contro l the reacto r and maintain it in a safe shutdown condi tion to diagnose, OBA~ In additi on, the 90 day Completion Time is a reasonable time boundary.

p*lan *and_possibly repai r, and test most problems with the CRE g for SR 4.7.2 .2 verifi es the OPERABILITY of the CRE boundary by testin The detai ls of unfilt ered air inleakage past the CRE bound ary and into the CRE.

l Room Envelo pe Habit abilit y Progra m.

• the testin g are specif ied in the Contro CRE occupants The CRE is considered habita ble when the radiol ogica l dose to no more than 5 es of OBA conseq uence s is calcu lated in-the licens ing basis analys are protec ted from rem,.. Total Effec tive Dose Equivalent and the CRE occup ants

.2 verifi es that the unfilt ered air haiard~us*~hemicals and smoke. SR 4.7.2 d in the licens ing inleak age into the CRE is no greate r than the flow rate assume unfilt ered air inleak age is greate r than basis* analyses of OBA consequences. When d. Requir ed Action the assumed flow rate, Required Actinn 3.7.2 .a.2 must be entere status provided 3.7.2 .a.2.c allows time to restor e the CRE boundary to OPERABLElicens ing basis mitig ating action s can ensure that the CRE remain s within the Compensatory habit abilit y limits for the occupants following an accid ent. .3, (Ref. 3) which measures are discussed in Regulatory Guide 1.196 , Sectio n C.2.7 dix F (Ref. 4). These endor ses, with excep tions, NEI 99-03, Section 8.4 and Appen as required by compensatory measures may also be'used as mitiga ting action s also be used as Required Action 3.7.2 .a.2.b . Temporary analy tical methods may s for restor ing the compensatory measures to resto re OPERABILITY (Ref. 5). Option basis OBA CRE boundary to OPERABLE status include changing the licens ing of these consequence analy sis, repair ing the CRE boundary, or a combination ctive action , a action s. Depending upon the nature of the problem and the corre the CRE boundary full scope inleakage test may not be necessary to estab lish that has been restor ed to OPERABLE status .

B 3/4 7-lb Amendment No. 149 LIMERICK - UNIT 2

PLANT SYSTEMS CONTROL ROOM EMERGENCY FRESH AIR SUPPLY SYSTEM - COMMON SYSTEM (Continued)

C REEEBENCES

1. UFSAR Section 6.4

2. UFSAR Section 9.5

3. Regulatory Guide 1.196

4. NE! 99-03, "Control Room Habitability Assessment Guidance," June 2001.

5. Letter from Eric J. Leeds (NRC) to James W. Davis (NE!) dated January 30, 2004, "NE! Draft White Paper, Use of Generic Letter 91-18 Process and Alternative Source Terms ih the Context of Control Room Habitability." (ADAMS Accession No. ML040300694).

3/4,7,3 REACTOR CORE ISOLATION COOLING SYSTEM The reactor core isolation cooling (RCIC) .system is provided to assure adequate core cooling in the event of reactor isoiation from its primary heat sink and the loss of feedwater flow to the reactor vessel without requiring actuation of any of the emergency core cooling system equipment. The RCIC system is conservatively required to be OPERABLE whenever reactor pressure ex-ceeds 150 psig. This pressure is substantially below that for which low pressure core cooling systems can provide adequate core cooling. Management of gas voids 1s important to RCIC System OPERABILITY.

c*

The RCIC system specifications are applicable during OPERATIONAL CONDITIONS 1, 2, and 3 when reactor vessel pressure exceeds 150 psig because RCIC 1s the primary non-ECCS source of emergency core cooling when the reactor is pressurized.

With the RCIC system inoperable, adequate core cooling is assured by the OPERABILITY of the HPCI system and justifies the specified 14 day out-of-service period. A Note prohibits the application of Specification 3.0.4.b to an inoperable RCIC system. There is an increased risk ~ssociated with entering an OPERATIONAL CONDITI,ON or other specified condition in the Applicability with an inoperable RCIC subsystem and the provisions of Specification 3.0.4.b, which allow entry into an OPERATIONAL CONDITION or other specified condition in the Applicability with the Limiting Condition for Operation not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.

The surveillance requirements provide adequate assurance that RCIC will be OPERABLE when required. Although all active components are testable and full flow can be demonstrated by recirculation during reactor operation, a complete functional test requires reactor shutdown.

LIMERICK - UNIT 2 B 3/4 7-lc Amendment No. ~.+49, L Associated with Amendment No. 178

PLANT SYSTEMS E

3/4.7.3 REACTOR CORE ISOLATION COOLING SYSTEM (Continued)

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 required RCIC System and may also prevent water hammer, pump cavitation, and pumping of noncondensible gas into the react9r vessel.

• Selection of RCIC 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 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 locations exceeds an acceptance criteria for gas volume at the suction or discharge of a pump), the Surveillance is not 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 subset 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.

Surveillance 4.7.3.a.2 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 rapid~y close the system vent flow path if directed.

LIMERICK - UNIT 2 B 3/4 7-ld Associated with Amendment No. 178 I

'\

PLANT SYSTEMS

\ BASE 3/4.7.4 SNUBBERS The "Snubber Program" manages the requirement for demonstrating snubber operability (examination, testing and service life monitori*ng) as reflected.in TS Section 6.8.4.k thereby.ensuring the TS remains consistent with the ISI program. The program for in service testing of snubbers in accordance with ASME OM Code and the applicable addenda as required by 10 CFR 50.SSa(g) is required to include evaluation of supported components/systems when snub~ers are found*to be inoperable .

~

LIMERICK - UNIT 2 B 3/4 7-2 Amendment No. +/--5-, 184

THIS PAGE INTENTIONALLY LEFT BLANK

(('

PLANT SYSTEMS "BASES

\

/ SNUBBERS (Coriti nued) 3/4.7.5 SEALED SOURCE CONTAMINATION The limitations on removable contamination for sources requ1r1ng leak testing, including alpha emitters, is based on 10 CFR 70.39(c) limits for. plutonium. This limitation will ensure that leakage_ from byproduct, source, and special nuclear material sources will not exceed allowable intake values. Sealed sources are classified into three* groups according to their use, with surveillance requirements commensurate with the probability of damage to a source in that group. Those sources which are frequently handled are required to be tested more often than those which are not. Sealed sources which are continuously enclosed within*a shielded mechanism, i.e,, s~aled sources within radiation monitoring devices, are considered to be stored and need not be tested unless they are removed from the shiel.ded mechanism.

LIMERICK - UNIT 2 B 3/4 7-3 Amendment No. -3:9, 4-2-, 184

• . . .*.:.':Pl.ANT. .SYSTEMS.*. . . .

.* ..... . -::~~ses:;: . *:* . '. \~: ,. :. *. * ** *-,. . :. ** , ... ., '*,, ...

... ". *... * :.. *.*);-(*. .

. . .. . ~ .

• *. . . * :* s'EALED** SOURCE CONTAMI°NATION. c*co'ni*1 nued) * *: *. *.. :* . . *.

0

.. *. :-. .:'*. *:.;, *: . ~ ..

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..... ,.. *. *s.~art~up*, neutron :*s~ur~e. *.must* .b~t" lectk. ~ tested** ~Y* Jhe **manufact1:1rer. r.emotely* .in a*. * .. .

.. *.<hOt-'*c;*en.:.fac111ty.~< Pµe***.tcL th*f phy$icaF des1gn.,. of. *t~is( source-,:. ,f s1.x. ~onth* . *.* * ......

. . .*, ::. f.req'Qe:ncy*. f_or*,. i:ontail1nat.1or(testfng; 'provides :.'reasonable* assuran.c~*:~hat..the*: ,:*

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• proper.ly* con~ained~ * .* *.. * ... .-. . . *~ * *

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LIMERICK* UNIT 2 B 3/4 7*3a

• AUG 2 5 1989

PLANT SYSTEMS BASES

========= ========= ========= ======***

3/4 7.6 {Deleted) - INFORMATION FROM THIS SECTION RELOCATED TO THE TRM.

3/4.7.7 {Deleted) - INFORMATION FROM THIS SECTION RELOCATED TO THE TRM.

\

J LIMERICK - UNIT 2 B 3/4 7-4 Amendment No.68 DfC 2 0 1995

PLANT SYSTEMS BASES 3/4 7.8 MAIN TURBINE BYPASS SYSTEM The required OPERABILITY of the main turbine bypass system is consistent with the assumptions of the feedwater controller failure analysis in the cycle specific transient analysis.

The main turbine bypass system is required to be OPERABLE to lim1t peak pressure in the main steam lines and to maintain reactor pressure within acceptable limits during events that cause rapid pressurization such that the Safety Limit MCPR is not exceeded. With the main turbine bypass system inoperable, continued operation is based on the cycle specific transient analysis which has been performed for the feedwater controller failure, maximum demand with bypass failure.

(

(__

LIMERICK - UNIT 2 B 3/4 7-5 Amendment No. 16 OCT 2 4 1991

3/4.8 ELECTRICAL POWER SYSTEMS BASES 3/4.8,1. 3/4.8.2. and 3/4.8.3 A.C. SOURCES. D.C. SOURCES. and ONSITE POWER DISTRIBUTION SYSTEMS The OPERABILITY of the A.C. and D.C. power sources and associated will be distri butio n systems during operation ensures that suffic ient power Cl) the safe availa ble to supply the safety -relat ed equipm ent requir ed for tion and contro l of accide nt shutdown of the facili ty and (2) the mitiga and condi tions within the facili ty. The minimum speci fied independent s satisf y the redundant A.C. and D.C. power sources and distri butio n system Appen dix A to 10 CFR Part 50.

requirements of General Design Criter ion 17 of switc hes, An offsi te power source consi sts of all breakers, transf ormer s, from the to transm it power interr uptin g devic es, cablin g, and controls required or buses. The offsi te transm ission network to the onsite Class lE emergency bus is dependent upon determination of the OPERABILITY of an offsit e source of power the design basis grid and plant facto rs that, when taken togeth er, descr ibe of these factor s calcu lation requirements for voltage regula tion. The combithe nation plant emerg ency ensures that the offsi te sourc e(s), which provide power to ed to achieve and buses, wi~l be fully. capab le of supporting the equipment requir .

maintain safe shutdown during postulated accidents and trans ients The plant facto rs consi st of the status of the Startu p Transf ormer (#10 and

1. 20) load tap changers (LTCs), the status of the Safeguard ency Transformer (#101 and buses on the

1. 201) load tap changers (LTCs), and the alignment of emerg to be considered

_) Safeguard Buses (101-Bus and 201-Bus). For an offsi te sourcesource to the 101-Bus, operable, both of its respe ctive LTCs (#10 AND #101 for the e, and in automatic.

1. 20 AND #201 for. the source to the 201-Bus) must be in servic ered operable, the For the third offsi te source (from 66 kV System) to be consid in servic e and in connected Safeguard Transformer (#101 or #201) LTC must be the emergency buses and automatic. There is a dependency between the alignment of the allowable post contingency voltage drop percentage.

and the The grid facto rs consi st of actual grid voltage levels Creal time) post trip contingency voltage drop percentage value .

voltag e The minimum offsi te source voltage levels are estab lished by the notify LGS system opera tor (TSO) will regula tion calcu lation . The transmission when an agreed upon limit is approached.

value The post trip contingency percentage voltage drop is a calcu lated one of the the trippi ng of determined by the TSO that would occur as a resul t of upon limit is

• Limerick gener ators. The TSO wil 1 notify LGS when an agreed exceeded. The voltage regula tion calcu lation estab lishes theaccep acceptable the table value is percentage* voltage drop based upon pl ant confi gurat ion; dependent upon plant config uratio n.

and 48 Due to the 20 Source being derived from the tertia ry of the 4A and the 500 kV system transformer, its opera bility is influenced by both the 230 the 230 kV system.

kV. system. The 10 Source opera bility is *only influe nced by B 3/4 8-1 EGR QQ 0937, EGR gg GQe82, LIMERICK - UNIT 2 ECR 05-00297 Amendment No. ~

3/4.8 ELECTRICAL POWER SYSTEMS BASES 3/4.8.1, 3/4.8,2. and 3/4.8.3 A.C. SOURCES, p,c. SOURCES. and ONSITE POWER DISTRIBUTION SYSTEMS The anticipated post trip contingency voltage drop for the 66 kV Source (Transformers 8A/8B) is calculated to be less than the 230 kV and 500 kV systems.

This is attributed to the electrical distance between the output of the Limerick generators and the input to the 8A/8B transformers. Additionally, the Unit Auxiliary Buses do not transfer to the SA/SB transformers; this provides margin to the calculated post trip contingency voltage drop limit.

There are various means of hardening the 10 and 20 Sources to obtain additional margin to the post trip contingency voltage drop limits. These m~ans include, but are not limited to, source alignment of the 4 kV buses, preventing transfer of 13 kV buses, limiting transfer of selected 13 kV loads, and operation with 13 kV buses on the offsite sources. The specific post trip contingency voltage drop percentage limits for these alignments are identified in the voltage regulation calculation, and controlled via plant procedures. There are also additional restrictions that can be applied to these limits in the event that an LTC is*taken to manual, or if the bus alignment is outside the Two Source rule set.

LGS unit post trip contingency voltage drop percentage calculations are performed by the PJM Energy Management System (EMS). The PJM EMS consists of a primary and backup system. LGS will be notified if the real time contingency analysis capability of PJM is lost. Upon receipt of this notification, LGS is to (

request PJM to provide an assessment of the current condition of the grid based on _

the tools that PJM has available. The determination of the operability of the offsite sources would consider the assessment provided by PJM and whether the current condition of the grid is bounded by the grid studies previously performed for LGS.

Based on specific design analysis, variations to any of these parameters can be determined, usually at the sacrifice of another parameter, based on plant conditions. Specifics regarding these variations must be controlled by plant procedures or by operability determinations, backed by specific design calculations.

The ACTION requirements specified for the levels of degradation of the power sources provide restriction upon continued facility operation commensurate with the level of degradation. The OPERABILITY of the power sources are con-sistent with the initial condition assumptions of the safety analyses and are based upon maintaining at least two of the onsite A.C. and the corresponding D.C. power sources and associated distribution systems OPERABLE during accident conditions coincident with an assumed loss-of-offsite power and single failure of the other onsite A.C. or D.C. source. At least two onsite A.C. and their corresponding D.C. power sources and distribution systems providing power for at least two ECCS divisions (1 Core Spray loop, 1 LPCI pump and 1 RHR pump in suppression pool cooling) are required for design basis accident mitigation as discussed in UFSAR Table 6.3-3.

LIMERICK - UNIT 2 B 3/4 8-la eCR QQ QQ37, !CR 99 QQe82, aCR Ge QQ297, Amendment No.~. ECR 09-00284

3/4.8 ELECTRICAL POWER SYSTEMS

\ BASES S (Continued)

A.C. SOURCES. O.C. SOURCES. and ONSITE POWER DISTRIBUTION SYSTEM CREFAS, SGTS, Onsite A.C. opera bility requirements for common systems such as on action RHRSW and ESW are addressed in the appro priate system speci ficati statem ents.

A.C. Sources diesel gener ators As requir ed by Speci ficati on 3.8.1 .1, Action e, when one or more that all remaining are inope rable, there is an additi onal ACTION requirement to verify that depend on the requir ed systems, subsystems, trains , components, and devic es, also OPERABLE. The LPCI OPERABLE diesel gener ators as a source of emergency power, arewhich only two trains are mode of the RHR system is considered a four trai~ system, of diesel gener ators are requir ed. The verifi catio n for LPCI is not required until two that a loss-o f-offs ite inope rable. This requirement is intended to provide assurance on of critic al sjstems power event will not resul t in a complete loss of safety functi inope rable. The term during the period when one or more of the diesel gener ators are by examining logs or verify as used in this conte xt means to admin istrati vely check f-serv ice for maintenance other information to determine if certai n components are out-oe requirements needed to or other reasons. It does not mean to perform the surve illanc demonstrate the OPERABILITY of the component.

Speci ficati on Speci ficati on 3.8.1 .1, Action i, prohi bits the applic ation of risk assoc iated with increa sed

) 3.0.4 .b to an inope rable diesel gener ator. There is an tion in the Appli cabili ty with

.___} enteri ng an OPERATIONAL CONDITION or other specif ied condi ions of Speci ficati on 3.0.4 .b, an inope rable diesel gener ator subsystem and the provis fied ~ondi tion in the which allow entry into an OPERATIONAL CONDITION or other speci not met after perfor mance of*a Appli cabili ty with the Limiting Condition for Operation should not be applie d in risk assessment addre ssing inoperable ~ystems and components, this circumstance.

If it can be determined that the cause of the inope rable EOG the does not exist on the then EOG start test (SR remaining operable EDG(s), based on a common-mode evalu ation, ise be determined that 4.8.1 .1.2.a .4) does not have to be performed. If it cannot otherw remain ing EDG(s ), then the cause of the initia l inope rable EOG does not exist on the assurance of continued satisf actor y performance of the start test suffic es to provide l inope rabili ty exists on opera bility of the remaining EDG(s). If the cause of the initia rable upon discovery and the remaining operable EDG(s), the EDG(s) shall be declar ed inope shall ~e entere d. In the the appro priate action statem ent for multip le inope rable EDGs to completing the EOG start event the inoperable EOG is restor ed to operable status prior requir ed in Speci ficati on test (SR 4.8.1 .1.2.a .4) or common-mode failur e evalu ation as 3.8.1 .1, the plant corre ctive action program shall continue not to* evalu ate the common-mode subje ct to the time failur e possi bility . However, this continued evalu ation is contained in the inope rable const raint imposed by the action statem ent. The provis ions are based on Generic Letter EOG action requir ement s; 6hat avoid unnecessary EOG testin g Surve illanc e 93-05, ~Line-Item Technfoal Speci ficati ons Improvement to Reduce ber 27, 1993.

Requirements for Testin j;~uri ng Power Operation," dated Septem B 3/4 8-lb ECR 00 00937, EGR 99 00682, LIMERICK - UNIT 2 Amendment No. J-2..~84.

~.-+/--09-002 ECR

3/4.8 ELECTRICAL POWER SYSTEMS BASES

(

A,C, SOURCES, p,c, SOURCES, and ONSITE POWER DISTRIBUTION SYSTEMS CCont1nued)

The t1me, voltage, and frequency acceptance cr1ter1a spec1f1ed for the EDG sfngle largest post-acc1dent load rejection test CSR 4.8.1.1.2.e. 2) are der1ved from Regulatory Gu1de 1.9, Rev. 2, December 1979, recommendat1ons. The test 1s acceptable 1f the EDG speed does not exceed the nom1nal (synchronous) speed plus 751 of the d1fference between nom1nal speed and the overspeed tr1p setpo1nt, or 1151 of nominal, wh1chever is lower.

Th1s computes to be 66.5 Hz for the LGS EDGs. The RHR pump motor represents the single largest post-accident load. The i.s seconds spec1f1ed is equal to 601 of the 3-second load sequence interval assoc1ated with sequenc1ng the next load followingJthe RHR pumps in response to an undervoltage on the electrical bus concurrent with a LOCA. Th1s provides assurance that EDG frequency does not exceed predeterm1ned lim1ts and that frequency stab1lity 1s suff1cient to support proper load sequencing follow1ng a rejection of the largest s1ngle load.

o.c, sources With one div1s1on w1th one or two battery chargers inoperable (e.g., the voltage lim1t of 4.8.2.1.a.2 is not maintained), the ACTIONS provide a t1ered response that focuses on returning the battery to the fully charged state and restoring a fully qualif1ed charger to OPERABLE status in a reasonable t1me per1od. Act1on a.1.requ1res that the battery terminal voltage be restored to greater than or equal to the minimum establ1shed float voltage w1thin 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. Th1s t1me prov1des for returning the inoperable charger to OPERABLE status or prov1d1ng an alternate means of restoring (

battery terminal voltage to greater than or equal to the m1nimum established float voltage. Restor1ng the battery terminal voltage to greater than or equal to the min1mum established float voltage provides good assurance that, w1th1n 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />, the battery w111 be restored to its fully charged condition (Act1on a.2) from any discharge that might have occurred due to the charger 1noperab111ty.

A discharged battery having term1nal voltage of at least the m1n1mum established float voltage indicates that the battery 1s on the exponent1al charging current portion (the second part) of its recharge cycle. The time to return a battery to 1ts fully charged state under this condition 1s s1mply a funct1on of the amount of the previous d1scharge and the recharge character1st1c of the battery. Thus there is good assurance of fully recharg1ng the battery within 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />, avoid1ng a premature shutdown with its own attendant r1sk.

If established battery terminal float voltage cannot be restored to greater than or equal to the min1mum establ1shed float voltage with1n 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, and the charger is not operating in the current-11miting mode, a faulty charger 1s indicated. A faulty charger that is incapable of ma1ntafn1ng estab11shed battery terminal float voltage does not provide assurance that it can revert to and operate properly 1n the current 11mit mode that is necessary during the recovery per1od following a battery d1scharge event that the DC system is designed for.

(_ -

LIMERICK - UNIT 2 B 3/4 8-lc E,A gg gg937, ECR gg QQfi82, Amendment No.~.~ . 150

3/4.8 ELECTRICAL POWER SYSTEMS

\BASES A.C, SOURCES, D.C, SOURCES. and ONSITE POWER DISTRIBUTION SYSTEMS (Continued)

If the charger is operating in the current limit mode after 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> that is an indicat ion that the battery is partial ly discharg ed and its capacit y margins will be battery to its fully charged conditi on in this case is a reduced. The time to return the ted DC function of the battery charger capacit y, the amount of loads on the associa teristic of the system, the amount of the previou s dischar ge, and the recharg e charac battery . The charge time can be extensive, and t~ere is not adequate assuran ce that it can be recharged within 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> (Action a.2).

Action a.2 require s that the battery float current be verifie d for Divisio ns 1 and 2 as.::: 2 amps, and for Divisions 3 and 4 as.::: 1 amp. This indicat es that, if the battery had been discharged as the result of the inoperable battery charger , it has now been fully recharged. If at the expirat ion of the initial 18 hour2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> period the battery float may be additio nal battery problem s.

current is not within limits this indicat es there Action a.3 limits the restora tion time for the inoperable battery charger to 7 an alterna te means of restori ng battery termina l days. This action is applica ble if has been used voltage to greater than or equal to the minimum establis hed float voltage ss lE battery charger ). The 7 days reflect s a reasona ble (e.g., balance of plant non-Cla time to effect restora tion of the qualifi ed battery charger to OPERABLE status.

With one or more cells in one or more batteri es in one divisio n< 2.07 V, require the ation of the d battery cell is degraded. Per Action b.l, within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, verific l voltage_

~battery charger OPERABILITY is made by monitoring the battery termina

'--" (4.8.2. 1.a,2) and of the overall battery state of charge by monitoring ent the battery float charge current (4.8.2. 1.a.1). This assures that there is still suffici battery capacit y to perform the intended functio n. Therefo re, with one or more cells in one or more batteri es< 2.07 V, continu ed operati on is permitt ed for a limited period up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Division 1 or 2 with float curren t> 2 amps, or Division 3 or 4 with float current y has occurre d. This

> 1 amp, indicat es that a partial discharge of the battery capacit may be due to a temporary loss of a_ battery charger or possibl y due to one or more battery cells in a low voltage condition reflect ing some loss of capacitILITY y. Per Action b.2, within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> verific ation of the required battery charger OPERAB is made by monitoring the battery terminal voltage .

Since Actions b.1 and b.2 only specify "perform," a failure of 4.8.2.1 .a.1 or result in this Action not being met. Howeve r, 4.8.2.1 .a.2.ac ceptan ce criteri a does not (s), dependi ng on if one of the Surveil lance Requirements is failed the approp riate Action the cause of the failure s, is also entered .

If the Action b.2 conditi on is due to one or more cells in a low voltage conditi on this is not but still greater than 2.07 V and float voltage is found to be satisfa ctory, ble time prior indicat ion of a substa ntially discharged battery and 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> is a reasona to declaring the battery inopera ble.

With one or more batteri es in one divisio n with one or mor.e cells electro lyte minimum establi shed design limits, Ci .e.,

level above the top of the plates, but below the suffici ~nt jJreate r than the minimum level indicat ion mark), the battery still retains

"""'illil""Capacity to perform the intende d functio n. Per Action b.3, within 31 days the minimum establi shed design limits for electro lyte level must be re-esta blished .

LIMERICK - UNIT 2 B 3/4 8-ld Amenqment No. 126 I

3/4.8 ELECTRICAL POWER SYSTEMS BASES

(

A.C, SOURCES, P,C, SOURCES. and ONSITE POWER DISTRIBUTION SYSTEMS (Continued)

With electrolyte level below the top of the plates there is a potential for dryout and plate degradation. Action b.3 addresses this potential (as well as provisions in Specification 6.8.4.h, "Battery Monitoring and Maintenance Program"). Within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> level is required _to be restored to above the top of the plates. The Action requirement to verify that there is no leakage by visual inspection and the Specification 6.8.4.h item to initiate action to equalize and test in accordance with manufacturer's recommendation are taken from Annex D of IEEE Standard 450-1995. They are performed following the restoration of the electrolyte level to above the top of the ~lates. Based on the results of the manufacturer's recommended testing the battery may have to be declared inoperable and the affected cell Cs) replaced.

Per Action b.4. with one or more batteries in one division with pilot cell temperature less than the minimum established design limits. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is allowed to restore the temperature to within limits. A low electrolyte temperature limits the current and power available. Since the battery is sized with margin. while battery capacity is degraded, sufficient capacity exists to perform the intended function and the affected battery is not required to be considered inoperable solely as a result of the pilot cell temperature not met.

Per Action b.5, with one or more batteries in more than one division with battery parameters not within limits there is not sufficient assurance that battery capacity has not been affected to the degree that the batteries can still perform their required function, given that multiple divisions are involved. With multiple divisions involved, this potential could result in a total loss of function on multiple systems that rely (

upon the batteries. The longer restoration times specified for battery parameters on one -

division not within limits are therefore not appropriate, and the. parameters must be restored to within limits on all but one division within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

When any battery parameter is outside the allowances of Actions b.l, b.2, b.3, b.4, or b.5, sufficient capacity to supply the maximum expected load requirement is not ensured and a 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> restoration time is appropriate. Additionally, discovering one or more batteries in one division with one or more battery cells float voltage less than 2.07 V and float current greater than limits indicates that the battery capacity may not be sufficient to perform the intended functions. The battery must therefore be restored within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

The OPERABILITY of the minimum specified A.C. and D.C. power sources and associated distribution systems during shutdown and refueling ensures that (1) the facility can be maintained in the shutdown or refueling condition for extended time periods and (2) sufficient instrumentation and control capability is available for monitoring and maintaining the unit status.

The surveillance requirements for demonstrating the OPERABILITY of the diesel generators are in accordance with the recommendations of Regulatory Guide 1.9, "Selection of Diesel Generator Set Capacity for Standby Power l

LIMERICK - UNIT 2 B 3/4 8-le Amendment No.~.

eGR 00 00967, fGR gg 00e82, ECR 09-00284

3/4.8 ELECTRICAL POWER SYSTEMS BASES A.C. SOURCES. D.C. SOURCES. and ONSITE POWER DISTRIBUTION SYSTEMS (Continued)

Supplies, March 10, 1971, Regulatory Guide 1.137 "Fuel-Oil Systems for Standby Diesel Generators," Revision 1, October 1979 and Regulatory Guide 1.108, "Periodic Testing of Diesel Generator Units Used as Onsite Electric Power Systems at Nuclear Power Plants," Revision 1, August 1977 except for paragraphs C.2.a(3), C.2.c(l),

C.2.c(2), C.2.d(3) and C.2.d(4), and the-periodic testing will be performed in accordance with the Surveillance Frequency Control Program. The exceptions to Regulatory Guide 1.108 allow for gradual loading of diesel generators during testing and decreased surveillance test frequencies (in response to Generic Letter 84-15).

The single largest post-accident load on each diesel generator is the RHR pump.

The Surveillance Requirement for removal of accumulated water from the fuel oil storage tanks is for preventive maintenance. The presence of water does not necessarily represent failure of the Surveillance Requirement, provided the accumulated water is removed during performance of the Surveillance.

Accumulated water in the fuel oil storage tanks constitutes a collection of water at a level that can be consistently and reliably measured. The minimum level at which accumulated water can be consistently and reliably measured in the fuel oil storage tank sump is 0.25 inches. Microbiological fouling is a major cause of fuel oil degradation. There are numerous bacteria that can grow in fuel oil and cause fouling, but all must have a water environment in order to survive.

Removal of accumulated water from the fuel storage tanks once every (31) days eliminates the necessary environment for bacterial survival. This is the most effective means of controlling microbiological fouling. In addition, it eliminates

\ the potential for water entrainment in the fuel oil during DG operation~ Water may

.__,) come from any of several sources, including condensation, ground water, rain water, contaminated fuel oil, and from breakdown of the fuel oil by bacteria.

Frequent checking for and removal of accumulated water minimizes fouling and provides data regarding the watertight integrity of the fuel oil system. The Surveillance Frequencies are established by Regulatory Guide 1.137.

The surveillance requirements for demonstrating the OPERABILITY of the units batteries are in accordance with the recommendations of IEEE Standard 450-1995, "IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented Lead-Acid Batteries for Stationary Applications."

Verifying battery float current while on float charge (4.8.2.1.a.l) is used to determine the state of charge of the battery. Float charge is the condition in which the charger is supplying the continuous charge required to overcome the internal losses of a battery and maintain the battery in a charged state. The float current requirements are based on the float current indicative of a charged battery. Use of float current to determine the state of charge of the battery is consistent with IEEE-450-1995. I*

This Surveillance Requirement states the float current requirement is not required to be met when battery terminal voltage is less than the minimum established float voltage of 4.8.2.1.a.2. When this float voltage is not maintained the Actions of LCD 3~8.2.1, Action b., are being taken, which provide the necessary and appropriate verifications of the battery condition. Furthermore, the float current limits are established based on the float voltage range and is not directly applicable when this voltage is not maintained.

LIMERICK - UNIT 2 B 3/4 8-2 Amendment No. J-4,~,gg,iie147 correction ltr. 6/19/95 ECR 97 01067

I (

(_

AU6'°2 1 28111 ECR 00-00937

3/4.8 ELECTRICAL POWER SYSTEMS BASES

\

A.C. SOURCES. D.C. SOURCES. and ONSITE POWER DISTRIBUTION SYSTEMS (Continued)

Verifying, per 4.8.2.1.a.2, battery terminal voltage whi1e on float charge for the batteries helps to ensure the effectiveness of the battery chargers, which support the ability of the batteries to perform their intended function. Float charge is the condition in which the charger is supplying the continuous charge required to overcome the internal losses of a battery and maintain the battery in a fully charged state while supplying the continuous steady state loads of the associated DC subsystem. On float charge, battery cells will receive adequate current to optimally charge the battery. The voltage requirements are based on the minimum float voltage established by the battery manufacturer (2.20 Vpc, average, or 132 Vat the battery terminals).

This voltage maintains the battery plates in a condition that supports maint~ining the grid life (expected to be approximately 20 years).

Surveillance Requirements 4.8.2.1.b.l and 4.8.2.1.c require verification that the cell float voltages are equal to or greater than 2.07 V.

The limit specified in 4.8.2.1.b.2 for electrolyte level ensures that the plates suffer no physical damage and maintains adequate electron transfer capability.

Surveillance Requirement 4.8.2.1.b.3 verifies that the pilot cell temperature is greater than or equal to the minimum established design limit (i.e., 60 degrees Fahrenheit). Pilot cell electrolyte temperature is maintained above this temperature to assure the battery can provide the required current and voltage to meet the design requirements. Temperatures lower than assumed in battery sizing calculations act to inhibit or reduce battery capacity.

Surveillance Requirement 4.8.2.1.d.1 verifies the design capacity of the battery chargers. According to Regulatory Guide 1.32, the battery charger supply is recommended to be based on the largest combined demands of the various steady state loads and the charging capacity to restore the battery from the design minimum charge state to the fully charged state, irrespective of the status of the unit during these demand occurrences. The minimum required amperes and duration ensures that these requirements can be satisfied.

Surveillance Requirement 4.8.2.1.d.l requires that each battery charger be capable of supplying the amps listed for the specified charger at the minimum established float voltage for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The ampere requirements are based on the output rating of the chargers. The voltage requirements are based on the charger voltage level after a response to a loss of AC power. This time period is sufficient for the charger temperature to have stabilized and to have been maintained for at least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

A battery service test, per 4.8.2.1.d.2, is a special test of the battery's capability, as found, to satisfy the design requirements (battery duty cycle) of the DC electrical power system. The discharge rate and test length corresponds to the design duty cycle requirements as specified in the UFSAR.

LIMERICK - UNIT 2 B 3/4 8-2a Amendment No . .gg,~.147 ECR 97 01067

3/4,8 ELECTRICAL POWER SYSTEMS BASES A.C. SOURCES, P,C, SOURCES. and ONSITE POWER DISTRIBUTION SYSTEMS (Continued)

A battery performance discharge test (4.8.2.1.e and f) is a test of constant current capacity of a battery, normally done in the as found condition , after having been in service., to detect any change in the capacity determined by the acceptance test. The test is intended to determine overall battery degradation due to age and usage. Degradation (as used in 4.8.2.1.f ) is indicated when the battery capacity drops more.than lOZ from its capacity on the previous performance test, or is below 90% of the manufact urer's rating.

Either the battery performance discharge test or the modified performance discharge test is acceptable for satisfyin g 4.8.2.1.e and 4.8.2.1.f ; however, only the modified performance discharge test may be used to satisfy the battery service test requirements of 4.8.2.1.d .2.

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LIMERICK - UNIT 2 B 3/4 8-2b Amendment No. 126

ELECTRICAL POWER SYSTEMS

)

3/4,8.4 ELECTRICAL EQUIPMENT PROTECTIVE DEVICES The RPS Electric Power Monitoring System is provided to isolate the RPS bus from the RPS/UPS inverter or an alternate power supply in the event of overvoltage, undervoltage, or underfrequency. This system protects the loads connected to the RPS bus from unacceptable voltage and frequency conditions. The essential equipment powered from the RPS buses includes the RPS logic, scram solenoids, and valve isolation logic.

The Allowable Values are derived from equipment design limits, corrected for calibration and 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 and include allowances for instrumentation uncertainties, calibration tolerances, and instrument drift.

The Allowable Values for the instrument settings are based on the RPS providing power within the design ratings of the associated RPS components (e.g.,

RPS logic, scram solenoids). The most limiting voltage requirement and associated line losses determine the settings of the electric power monitoring instrument channels.

LIMERICK - UNIT 2 B 3/4 8-3 Amendment No . .§.7.,

Bases btr 11/18/98, 9-&,

Associated.with Amendment No. 170

C THIS PAGE INTENTIONALLY LEFT BLANK

3/4.9 REFUELING OPERATIONS BASES 3/4.9.1 REACTOR MODE SWITCH Loclcing the OPERABLE reactor mode switch in the Shutdown or Refuel positio n, as specifi ed, ensures that the restric tions .on control rod withdraw al and refuelin g platform movement during the refueling operations- are properly activat ed.* These conditions reinfor ce the refuelin g procedures and reduce the probab ility of inadver tent critica lity, damage to reactor interna ls or fuel assemblies, and exposure of personnel to excessive radioac tivity.

3/4.9.2 INSTRUMENTATION The OPERABILITY of at least two* source range. 110nitors

,aonitoring capa.bili"'f"y is avai1ab1e* to detect changes in the ensures that redundant reacti-vity condition of the core. The minimum count rate is not required When sixteen assemblies are in the core. :ouring a typical core reloading, 'two, orthree fewer fuel irradia ted fuel-assemblies will be loaded adjacent to each SRM to produce orgreaterfour than the minimmn required count rate. Loading sequences are selecte d to provide for a continuous multiplying medium to be establis hed between the required oper-able SRMs and the~aa tion of the core alterati on. This enhance s the.ab ility of the SRMs to respond ta the loading of eacw fuel assembly.* During a core un-loading, the last fuel to be removed is that f~el adjacent to the SRMs.

3/4.9.3 CONTROL ROD POSITION The requirement that all control rods be inserte d during other CORE ALTERATIONS ensures that fuel will not be loaded into a cell without a control rod.

3/4.9.4 DECAY TIME The minimum*requirement for reactor subcrit icality prior to fuel ensures that suffici ent time has elapsed to allow the radioac tive decaymovemen of the t

short lived fission products. This decay time is consist ent with the assump-tions used in the acciden t analyses.

3/4.9.5 COMMUNICATIONS The requirement for comnunieations capabi lity ensures that personnel can be promptly informed of signifi cant changes in the refuelifacilit ng station or core reactiv ity conditi on during movement of fuel within the reactor ypressur status vessel. e LIMERICK - UNIT 2 B 3/4 9-1 AUE 2 5 1989

3/4.9 REFUELING OPERATIONS BASES (Coptjnued) (

3/4.9.6 REFUELING PLATFORM The OPERABILITY requirements ensure that Cl) the refueling platform will be used for handling control rods and fuel assemblies within the reactor pressure vessel, (2) each hoist has sufficient load capacity for handling fuel assemblies and control rods, (3) the core internals and pressure vessel are protected from excessive lifting force in the event they are inadvertentl y engaged during lifting operations, and (4) inadvertent criticality will not occur due to fuel being loaded into a unrodded cell.

Inadvertent criticality is prevented by the ref.ueling interlocks that block unacceptable operations (e.g., loading fuel into a cell with a control rod withdrawn or withdraw~l of a rod from the core while the grapple is over the core and loaded with fuel). The hoist loaded values identified in Sections 4.9.6.lb and 4.9.6.lc support the refueling interlock logic by ensuring that the hoist fuel loaded switches function with a load lighter than the weight of a single fuel assembly in water.

Load values represent fuel (load) on the grapple. The values of 485 +/- 50 pounds and 550 + 0, -115 pounds are both less than the weight of a single fuel assembly in water attached to the grapple. These load values ensure that as soon as a fuel assembly is grappled and lifted, the*refuelin g interlocks (control rod block and bridge motion interlock) are enforced as required. The hoist load weighing system is compensated for mast weight to ensure that lifting of components other than fuel assemblies (e.g., blade guides) do not cause inadvertent control rod blocks or bridge motion stops.

3/4.9.7 CRANE TRAVEL - SPENT FUEL STORAGE POOL (

The restriction on movement of loads in excess of the nominal weight of a fuel assembly and associated lifting device over other fuel assemblies in the storaga pool ensures that in the event this load is dropped 1) the activity release will be limited to that contained in a single fuel assembly, and 2) any possible distortion of fuel in the storage racks will not result in a critical array. This assumption is consistent with the activity release assumed in the safety analyses.

3/4.9.B and 3/4.9.9 WATER LEVEL* REACTOR VESSEL and WATER LEVEL - SPENT FUEL STORAGE POOL The restrictions on minimum water level ensure that sufficient water depth is available to remove 99% of the assumed 10% iodine gap activity released from the rupture of an irradiated fuel assembly. This minimum water depth is consistent with the assumptions of the accident analysis.

3/4.9.10 CONTROL ROD REMOVAL These specification s ensure that maintenance or repair of control rods or control rod drives will be performed under conditions that limit the probability of inadvertent criticality. The requirements for simultaneous removal of more than one control rod are more stringent since the SHUTDOWN MARGIN specification provides for the core to remain subcritical with only one control rod fully withdrawn.

LIMERICK* UNIT 2 B 3/4 9-2 Amendment No. ECR 06-00391

3/4.9 REFUELING OPERATIONS BASES (Continued)

) RESIDUAL HEAT REMOVAL AND COOLANT CIRCULATION 3/4.9.11 Irradiated fuel in the shutdown reactor core generates heat during the decay of fission products and increases the temperature of the reactor coolant. This decay heat must be removed by the RHR system to maintain adequate reactor coolant temperatu re.

RHR shutdown cooling is comprised of four (4) subsystems which make two (2) loops. Each loop consists of two (2) motor driven pumps, a heat exchanger, and associated piping and valves. Both loops have a common suction from the same recirculat ion loop. Two (2) redundant, manually controlled shutdown cooling subsystems of the RHR system provide decay heat removal. Each pump discharges the reactor coolant, after circulatio n through the respective heat exchanger, to the reactor via the associated recirculat ion loop. The RHR heat exchangers transfer heat to the RHR Service Water System.

An OPERABLE RHR shutdown cooling subsystem consists of one (1) OPERABLE RHR pump, one (1) heat exchanger, and the associated piping and valves. The requirement for having one (1) RHR shutdown cooling subsystem OPERABLE ensures that 1) sufficien t cooling capacity is available to remove decay heat and maintain the water in the reactor pressure vessel below 140°F, and 2) sufficien t coolant circulatio n would be available through the reactor core to assure accurate temperature indication .

Management of gas voids is important to RHR Shutdown Cooling Subsystem OPERABILITY.

• The requirement to have two (2) RHR shutdown cooling subsystems OPERABLE when there is less than 22 feet of water above the reactor vessel flange ensures that a single failure of the operating -loop will not result in a complete loss of residual heat removal capability . With the reactor vessel head removed and 22 feet of water above the reactor vessel flange, a large heat sink is available for core cooling. Thus, in the event of a failure of the operating RHR subsystem, adequate time is provided to initiate alternate methods capable of decay heat removal or emergency procedures to cool the core.

To meet the LCO of the two (2) subsystems OPERABLE when there is less than 22 feet of water above the reactor vessel flange, both pumps in one (1) loop or one (1) pump in each of the two (2) loops must be OPERABLE. The two (2) subsystems have a common suction source and are allowed to have a common heat exchange~ and common discharge piping. Additiona lly, each shutdown cooling subsystem can provide the required decay heat removal capability ; however, ensuring operabilit y of the other shutdown cooling subsystem provides redundancy.

The required cooling capacity of an alternate method of decay heat removal should be ensured by verifying its capability to maintain or reduce reactor coolant temperature either by calculatio n (which includes a review of component and system availabil ity to verify that an alternate decay heat removal method is available) or by demonstra tion. Decay heat removal capability by ambient losses can be considered in evaluating alternate decay heat removal capability .

LIMERICK - UNIT 2 B 3/4 9-2a Amendment No.~. ,e-l., ~ .

ECR 01 00386, ECR 06 00391, Associated with Amendment No. 178

3/4.9 REFUELING OPERATIONS 3/4.9.11 RESIDUAL HEAT REMOVAL AND COOLANT CIRCULATION (Continued) (

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 non-condensible gas into the reactor vessel. This surveillance verifies that the RHR Shutdown Cooling System piping is sufficiently filled with water prior to placing the system in operation when in OPCON 5. The RHR Shutdown Cooling System is OPERABLE when it is sufficiently filled with water to ensure that it can reliably perform its intended function.

The RHR Shutdown Cooling System is a manually initiated mode of the RHR System that is aligned for service using system operating procedures that ensure the RHR shutdown cooling suction and discharge flow paths are sufficiently filled with water.

An RHR Shutdown Cooling sub-system that is already in operation at the time of entry into the APPLICABILITY is OPERABLE. For an idle RHR.Shutdown Cooling subsystem, the surveillance is met through the performance of the operating procedures that place the RHR Shutdown Cooling subsystem in service.

With the required decay heat removal subsystem(s) inoperable and the required alternate method(s) of decay heat removal not available in accordance with Action "a",

additional actions are required to minimize any potential fission product release to the environment. This includes ensuring Refueling Floor Secondary Containment is OPERABLE; one (1) Standby Gas Treatment subsystem is OPERABLE; and Secondary (

Containment isolation capability (i.e., one (1) Secondary Containment isolation valve

• and associated instrumentation are OPERABLE or other acceptable administrative controls to assure isolation capability) in each associated penetration not isolated that is assumed to be isolated to mitigate radioactive releases. This may be performed as an administrative check, by examining logs or other information to determine whether the components are out of service for maintenance or other reasons. It is not necessary to perform the Surveillances needed to demonstrate the OPERABILITY of the components.

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

If no RHR subsystem is in operation, an alternate method of coolant circulation is required to be established within one (1) hour. The Completion Time is modified such that one (1) hour is applicable separately for each occurrence involving a loss of coolant circulation.

LIMERICK* UNIT 2 B 3/4 9-3 Amendment No.~

tCR 06 ooag1, Associated with Amendment No. 178

3/4.10 SPECIAL TEST EXCEPTIONS BASES 3/4.10.l PRIMARY CONTAINMENT INTEGRITY The requirement for PRIMARY CONTAINMENT INTEGRITY is not applicable during the period when open vessel tests*are being performed during the low power PHYSICS TESTS.

3/4.10.2 ROD WORTH MINIMIZER

. In order to perform the tests required in the technical specifications it is necessary to bypass the sequence restraints on control rod*movement. The additional surveillance requirements ~nsure that the specifications on heat generation rates and shutdown margin requirements are not exceeded during the period when these tests are being performed and that individual rod worths do not exceed the values assumed in the safety analysis.

• 3/4.10.3 SHUTDOWN MARGIN DEMONSTRATIONS Performance of shutdown margin demonstrations with the vessel head removed requires additional restrictions in order to ensure that criticality does not occur. These addition_a1 restrictions are specified in thh LCD.

3/4.10.4 RECIRCULATION ,LOOPS This special test ex*ception permits reactor criticality* under no flow conditions and is required* to perform certain startup and PHYSICS TESTS while

\ at low THERMAL POWER levels.

3/4.10.5 OXYGEN CONCENTRATION Relief from the oxygen concentration specifications is necessary in order to provide access to the primary containment dur.ing the initial startup and testing phase of operation. Without this access the startup and test program could be restricted and delayed.

3/4.10.6 TRAINING STARTUPS This special test except~on permits training startups to be performed with

• the reactor vessel depressurized at low THERMAL POWER and temperature while controlling RCS temperature with one RHR subsystem aligned in the shutdown*

cooling mode in order to minimize contaminated water discharge to the radioactive waste disposal system.

3/4.10.7 SPECIAL INSTRUMENTATION - INITIAL CORE LOADING Thh special te.st exception permits relief from the requirements for a minimum count rate while loading the first 16 fuel bundles to allow sufficient source-to-detector coupling such that ~inimum count rate can be achieved on an SRM. This is acceptable because of the significant margin to criticality while loading the initial 16 fuel bundles.

LIMERICK - UNIT 2 B 3/4 10-1 AUS 2 5 \989

3/4.10 SPECIAL TEST EXCEPTIONS 3/4.10.8 INSERVICE LEAK AND HYDROSTATIC TESTING (

This special test exception permits certain reactor coolant pressure tests to be performed in OPERATIONAL CONDITION 4 when the metallurgical characteristics of the reactor pressure vessel (RPV) or plant temperature control capabilities during these tests require the pressure testing at temperatures greater than 200°F and less than or equal to 212°F (normally corresponding to OPERATIONAL CONDITION 3). The additionally imposed OPERATIONAL CONDITION 3 requirements for SECONDARY CONTAINMENT INTEGRITY provide conservatism in response to an operational event.

Invoking the requirement for Refueling Area Secondary Containment Integrity along with the requirement for Reactor Enclosure Secondary Contaihment Integrity applies the requirements for Reactor Enclosure Secondary Containment Integrity to an extended area encompassing Zones 2 and 3. Operations with the Potential for Draining the Vessel, Core alterations, and fuel handling are prohibited in this secondary containment configuration. Drawdown and inleakage testing p1~formed for the combined zone system alignment shall be considered adequate to dem~nstrate integrity of the combined zones.

Inservice hydrostatic testing and inservice leak pressure tests requirkd by Section XI of the American Society of Mechanical Engineers CASME) Boiler and P~essure Vessel Code are performed prior to the reactor going critical after a refueling outage. The minimum temperatures Cat the required pressures) allowed for these tests are determined from the RPV pressure and temperature (P/T) limits required by LCD 3.4.6, Reactor Coolant System Pressure/Temperature Limits. These limits are conservatively based on the fracture toughness of the reactor vessel, taking into account anticipated vessel neutron fluence. With increased reactor fluence over time, the (

minimum allowable vessel temperature increases at a given pressure.

LIMERICK - UNIT 2 B 3/4 10~2 Amendment No.~

tGR 99 OOB64, 130

3/4.11 RADIOACTIVE EFFLUENTS BASES 3/4.11 .1.1 and 3/4.11 .1.2 (Deleted)

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1 THE INFORMATION FROM THESE SECTIONS I .HAS BEEN RELOCATED TO THE ODCM.

LIMERICK - UNIT 2 B 3/4 11-1 Amendment No .11 JAN O2 1991

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RADIOACTIVE EFFLUENTS 3/4.11.1.3 (Deleted) - INFORMATION FROM THIS SECTION RELOCATED TO THE ODCM.

3/4.11.1.4 LIQUID HOLDUP TANKS The tanks listed in this specificatio n include all those outdoor radwaste tanks that are not surrounded by liners, dikes, or walls capable of holding the tank contents and that do not have tank overflows and surrounding area drains connected to the li~uid radwaste treatment system.

• Restricting the quantity of radioactive material contained in the specified tanks provides assurance that in the event of an uncontrolled release of the tanks' contents, the resulting concentrations would be less than 10 times the limits of 10 CFR Part 20, Appendix B, Table 2, Column 2, at the nearest potable water supply and the nearest surface water supply in an UNRESTRICTED AREA.

3/4.11.2.1 (Deleted) - INFORMATION FROM THIS SECTION RELOCATED TO THE ODCM.

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LIMERICK - UNIT 2 B 3/4 11-2 Amendment No. -1+/-

Associated with Amendment No. 148

RADIOACTIVE EFFLUENTS BASES (

3/4 11.2. 2 through 3/4 11.2. 4 (Deleted)

THE INFORMATION FROM THESE SECTIONS HAS BEEN RELOCATED TO THE ODCM.

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LIMERICK* UNIT 2 l

B. 3/4 11-3 Amendment Nc.11 JAN O2 IJ!J I

RADIOACTIVE EFFLUENTS BASS 3/4.11.2.5 (Deleted) - INFORMATION FROM THIS SECTION RELOCATED TO THE TRM.

LIMERICK - UNIT 2 B 3/4 11-4 Amendment No.-1-+/-, 191

BASES 3/4.11.*2~6 MAIN CONDENSER.

Re str ict ing the gross provides* reasonable assrad ura ioa cti vit y rat e of ~able gases e tha t the tot al body exposurfroe-tm the main condenser exclusion area bound~ry winc ll not exceed.a small fra cti on o an individual at* the 100 in the event th is eff lue of t~e lim its of environment without tre atm ennt is* inadvertently dischatged dir ec tly to the 10 CFR Pa rt General Design Cr ite ria 60 and t. This spec1f1cat*ion implem 64 -of Appendi_x A _to 10 CFR.Pents*. the requirements of art 50 *.

3/4 .11 .t.7 *, 3/4 .11 .3, and 3/4

.11 .4 (Deleted)' - INFORMATION FROM'THES.E SECTIONS RELOCATED TO THE*. ODCM OR PCP.* .*

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IMERICK - UHIT"2 B 3/4 11-5 Amendment No .11 JAN O2 1991

3/4.12 RADIOLOGICAL ENVIRONMENTAL MONITORING BASES Section 3/4.12 (Deleted) 1 THE INFORMATION FROM THIS SECTION

-- I . HAS BEEN RELOCATED TO THE ODCM.

BASES PAGE 8 3/4 12-2 HAS BEEN INTENTIONALLY OMITTED.

LIMERICK - UNIT 2 B 3/4 12-1 Amendment No. 11 JAN O2 1991

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