View source for LR-N12-0156, Submittal of Updated Final Safety Analysis Report, Revision 26, Salem Units 1 & 2 Technical Specification Bases Changes, 10 CFR 54.37(b) Review Results and PSEG Nuclear LLC Quality Assurance Topical Report, NO-AA-10, Revision 82

{{Adams
| number = ML12157A209
| issue date = 05/21/2012
| title = Submittal of Updated Final Safety Analysis Report, Revision 26, Salem Units 1 & 2 Technical Specification Bases Changes, 10 CFR 54.37(b) Review Results and PSEG Nuclear LLC Quality Assurance Topical Report, NO-AA-10, Revision 82
| author name = 
| author affiliation = PSEG Nuclear, LLC
| addressee name = 
| addressee affiliation = NRC/NRR
| docket = 05000272, 05000311, 05000354
| license number = DPR-070, DPR-075, NPF-057
| contact person = 
| case reference number = LR-N12-0156, TS 6.16.d
| document report number = NO-AA-10, Rev 82
| document type = Quality Assurance Program, Topical Report, Updated Final Safety Analysis Report (UFSAR)
| page count = 486
}}

=Text=
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SALEM GENERATING STATION - UNIT NO.                     2 TECHNICAL SPECIFICATIONS LIST OF EFFECTIVE PAGES AS OF March 7,                     2012 Page       Amend        Page            Amend        Page          Amend      Page        Amend No.         No.         No.             No.          No.           No.        No.           No.
OPERATING                                        3/4  1-19    282        3/4  3-24    170 LICENSE                     2.0            3/4  1-20    282        3/4  3-25    127 3/4  1-21    197        3/4  3-26    127 1           06/30/11  2-1              197       3/4  1-22    197        3/4  3-27    238 2           06/30/11  2-2              224                               3/4  3-28    266 3           284       2-3              197                               3/4  3-29    266 4           06/30/11  2-4              206                3/4.2          3/4  3-30    266 5           06/30/11  2-5              261                               3/4  3-31    266 6           06/30/11  2-6              238       3/4  2-1     278        3/4  3-32    266 7           06/30/11  2-7             220        3/4  2-2     282        3/4  3-33    282 8           06/30/11  2-8             224        3/4  2-3     282        3/4  3-34    282 9           06/30/11  2-9             220        3/4  2-4     197        3/4  3-35    282 10          06/30/11                             3/4  2-5     239        3/4  3-36    282 11          283                   B2 .0          3/4  2-6     282        3/4  3-37    282 12          06/30/11                             3/4  2-7     282        3/4  3-38    282 13          06/30/11  B2-1             197       3/4  2-8     197        3/4  3-39    253 B2-2                       3/4  2-9     218        3/4  3-39a 278 B2-3            140        3/4  2-10    282        3/4  3-40    245 INDEX          B2-4            261*       3/4  2-11      72       3/4  3-41    282 B2-5        S2010-119*     3/4  2-12      72       3/4  3-43    282 I           206       B2-6            197        3/4  2-13               3/4  3-44    ---
II          197       B2-7              60       3/4  2-14               3/4  3-45    282 III          28                                  3/4  2-15    282        3/4  3-46/49 117 IV          265                                  3/4  2-16    282        3/4  3-50    282 V           281                  3/4.0           3/4  2-17    197        3/4  3-51    206 VI          264                                                          3/4  3-51a 263 VII         252       3/4 0-i         258                                3/4  3-51b 206 VIII        206       3/4 0-2         234                 3/4.3          3/4  3-51c 253 IX          277       3/4 0-3         279                                3/4  3-52    282 X           215                                  3/4  3-1     282        3/4  3-52a 282 XI          206                                  3/4  3-2     261        3/4  3-53    282 XII         281                  3/4.1           3/4  3-3     258        3/4  3-54    215 XIII        264                                  3/4  3-4     258        3/4  3-55    282 XIV         244                                  3/4  3-5     258        3/4  3-56/64 265 3/4   1-1       282 XV          244                                  3/4  3-6     121        3/4  3-65    218 XVI                  3/4    1-2       282 215       3/4   1-3       282        3/4  3-7     240        3/4  3-66    282 XVII        250                                  3/4  3-8       58       3/4  3-67    218 3/4   1-4       197 XVIII       269                                  3/4  3-9     266 3/4    1-5       197 3/4    1-6                  3/4  3-10    266 3/4    1-7       282        3/4  3-11    282                 3/4.4 1.0          3/4    1-8       282        3/4  3-12    282 3/4    1-9       279        3/4  3-13    282        3/4  4-1     282 1-1         174      3/4    1-10      279        3/4  3-14    282        3/4  4-2       44 1-2         252      3/4    I-ii      282        3/4  3-15    258        3/4  4-2a    282 1-3         276      3/4    1-12      282        3/4  3-16    116        3/4  4-3     206 1-4         262      3/4    1-12a     133        3/4  3-17    116        3/4  4-4     282 1-5         262      3/4    1-13      197        3/4  3-18      53       3/4  4-4a    282 1-6         263      3/4    1-14      282        3/4  3-19    258        3/4 4-4b     194 1-7         159      3/4    1-15        48       3/4  3-20    258        3/4  4-5     279 1-8          28      3/4    1-16      276        3/4  3-21    258        3/4 4-6      279 1-9          28      3/4    1-16a     282        3/4  3-22    258        3/4 4-7      282 3/4    1-17      213        3/4  3-23    174        3/4 4-8      177 3/4    1-18      282        3/4  3-23a   167        3/4 4-8a     282
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3/4  4-9     262        3/4 6-14      260       3/4  8-7a     246       3/4  11-12   215 3/4  4-10/15a 262       3/4 6-15      282       3/4  8-8      282       3/4  11-13   215 3/4  4-16    282        3/4 6-16/22 264         3/4  8-9      282       3/4  11-14   215 3/4  4-17    282                                3/4  8-10     280       3/4  11-15   282 3/4  4-18    282                                3/4   8-11    282       3/4  11-16    35 3/4  4-19    106                                3/4   8-11a   282       3/4  11-17   215 3/4  4-20/22 161                                3/4  8-11b    158       3/4  11-18   215 3/4  4-23    258                  3/4.7         3/4  8-12     282       3/4  11-19   215 3/4  4-24    112                                3/4  8-13     229 3/4  4-25    282        3/4 7-1       279       3/4  8-14     282 3/4  4-26               3/4 7-2       259       3/4   8-14a   282                3/4.12 3/4  4-27    282        3/4 7-3       225       3/4   8-14b   229 3/4  4-28    224        3/4 7-4       225       3/4  8-15     282       3/4 12-I     215 3/4  4-29    224        3/4 7-5       282       3/4  8-16     282       3/4 12-2     215 3/4  4-30    282        3/4 7-6       282       3/4  8-17     282 3/4  4-31    258        3/4 7-7       282       3/4  8-18      82 3/4  4-32    282        3/4 7-8 3/4  4-33    281        3/4 7-9       282                 3/4.9 3/4  4-34    282        3/4 7-10      279 3/4 7-11      282       3/4  9-1      282 3/4 7-12      282       3/4  9-2      282 3/4.5          3/4 7-13      282       3/4   9-3     273 3/4 7-14      282       3/4   9-4     282 3/4  5-1     282        3/4 7-15      269       3/4   9-5     277 3/4  5-2     282        3/4 7-16      269       3/4   9-6     277 3/4  5-3     184        3/4 7-17      282       3/4  9-7      277 3/4  5-3a      70       3/4 7-17a     269       3/4   9-8     282 3/4  5-4     282        3/4 7-18      252       3/4   9-9     279 3/4  5-5     282        3/4 7-19      282       3/4   9-10    245 3/4  5-6     282        3/4 7-20      252       3/4   9-11    282 3/4  5-6a    189        3/4 7-21      282       3/4   9-12    282 3/4   5-7     258        3/4 7-22                3/4  9-13     282 3/4   5-8     282        3/4 7-23      284 3/4   5-8a    282       3/4 7-24       284 3/4   5-9     282       Removed 7-    25 thru 7-27                            3/4.10 3/4 7-28      206 3/4.6          3/4 7-29      282       3/4  10-1     282 3/4 7-30      282       3/4  10-2     282 3/4   6-1     282       3/4 7-31       258       3/4  10-3 3/4   6-2     188       3/4 7-32       244       3/4  10-4     282 3/4   6-3     166                                3/4  10-5     282 3/4   6-4     195                  3/4.8 3/4  6-5     282 3/4  6-6     282       3/4    8-1     234                 3/4.11 3/4  6-7     282       3/4    8-2     234 3/4   6-8     206       3/4    8-2a    258       3/4  11-1     215 3/4   6-9     260       3/4    8-2b    234       3/4  11-2     215 3/4  6-10    282        3/4   8-3     282       3/4  11-5     215 3/4  6-11    282        3/4   8-4     282       3/4  11-6     215 3/4  6-11a   102        3/4   8-5     282       3/4  11-7     282 3/4   6-12    248       3/4    8-6     282       3/4  11-8     215
.3/4  6-13    282       3/4    8-7     185       3/4  11-9     215
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SALEM GENERATING STATION - UNIT NO.                    2 TECHNICAL SPECIFICATIONS LIST OF EFFECTIVE PAGES AS OF March 7,                    2012 Page        Amend        Page         Amend        Page              Amend      Page   Amend No.          No.         No.          No.          No.               No.        No.      No.
B3/4           B3/4 4-12      258     B3/4    9-la      244       6-19b     262 B3/4  4-13  224        B3/4    9-lb      282       6-19c     262 B3/4 0-1      110       B3/4  4-14    86       B3/4    9-Ic     273*       6-19d     262 B3/4 0-2      110       B3/4  4-15    86       B3/4    9-2      245        6-19e     262 B3/4 0-3      258       B3/4  4-16  224        83/4    9-3      277        6-19f     281 B3/4 0-3a     258       B3/4  4-17    86       B3/4    9-4      245        6-19g     284 B3/4 0-3b     258       B3/4  4-18  282                                    6-20      112 B3/4 0-4      234                              B3/4 10-1        206        6-21      278 B3/4 0-4a     234       B3/4 5-1                                           6-22      215 B3/4 0-5      237       B3/4 5-2    258        B3/4    11-1     215        6-23      215 B3/4 0-6      237       B3/4 5-3    258        B3/4    11-2     215        6-24      278 B3/4 0-7      237                              B3/4    11-3     215        6-24a     267 B3/4 0-8      258       B3/4 6-1    208        B3/4    11-4     215        6-24b     275 B3/4 0-9      279*      B3/4 6-la 208          B3/4    11-5     215        6-25      117 B3/4 6-lb 208          B3/4    11-6     243        6-26      279 B3/4 1-1      197       B3/4 6-1c 208          B3/4    11-7     215        6-27      236 B3/4 1-2      197       B3/4 6-id 282                                      6-27a     236 B3/4 1-3 SCN 05-042 B3/4 6-2        260*       B3/4 12-1        215        6-27b     236 B3/4 1-4       276*     B3/4 6-3   270*        B3/4 12-2        215        6-28      236 B3/4 1-5      282       B3/4 6-4   270*                                    6-29      215 B3/4 6-5 S2008-084*                                6-30      237 B3/4 2-1      197                                                          6-31      269 B3/4 2-2      197       B3/4 7-1    259                    5 .0 B3/4 2-3      197       B3/4 7-2    258 B3/4 2-4      218       B3/4 7-36/19/03        5-1                28 B3/4 2-5      218       B3/4 7-43 /7/97        5-2                28 B3/4 2-6      282       B3/4 7-5    269*       5-3                28 B3/4 7-5a S2011-238    5-3a               28 B3/4 3-1      282       B3/4 7-5b 269*         5-4              250 B3/4 3-la 282           B3/4 7-5c 269*         5-5              244 B3/4 3-2      282       B3/4 7-5d 269*         5-5a             244 B3/4 3-3      265*      B3/4 7-5e 282          5-5b             244 B3/4 3-3a 265*          B3/4 7-5f 269*         5-6 B3/4 3-4      282       B3/4 7-5g TSBC SCN     5-7 B3/4 3-5      282       06-015 B3/4 7-5h 252 B3/4 4-1      197       B3/4 7-5i 209                      6 .0 B3/4 4-2      282       B3/4 7-6    284 B3/4 4-3      262*      B3/4 7-7    284        6-1              175 B3/4 4-3a 262*          B3/4 7-8    182        6-2              274 B3/4 4-3b 262*          B3/4 7-9    244        6-3              112 B3/4 4-3c 262*          B3/4 7-10 244          6-4              112 B3/4 4-3d 262*          B3/4 7-11 282          6-5              112 B3/4 4-3e 262*          B3/4 7-12 244          6-6              112 B3/4 4-4      262*      B3/4 7-13 258          6-7              175 B3/4 4-4a 282                                  6-8              175 B3/4 4-5      282       B3/4 8-1     258       6-9/14           175 B3/4 4-6      258       B3/4 8-la    258       6-15             175 B3/4 4-7      224       B3/4 8-2    246        6-16             175 B3/4 4-8      224       B3/4 8-3    282        6-17             175 B3/4 4-9      224       B3/4 8-4    282        6-18             112 B3/4 4-10 224                                  6-19             235 B3/4 4-11 224           B3/4 9-1     244       6-19a            215
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SALEM GENERATING STATION - UNIT NO. 2 TECHNICAL SPECIFICATIONS LIST OF EFFECTIVE PAGES AS OF March 7,    2012 Page         Amend       Page      Amend       Page   Amend    Page Amend No.          No.         No.       No.         No. No.      No. No.
ENVIRONMENTAL PROTECTION PLAN APPENDIX B Cover         214 Tof C          77 1-1            77 2-1            77 2-2            77 3-1            77 3-2            77 3-3            77 4-1           214 4-2           196 5-1            77 5-2            77 5-3            77 5-4            77 ADDITIONAL CONDITIONS OPERATING LICENSE NO. DPR-75 APPENDIX C 1             227
*PSEG Issued LOEP 4 OF 4

SALEM GENERATING STATION UNIT NO. 2 FACILITY OPERATING LICENSE AND TECHNICAL SPECIFICATION LIST OF AMENDMENTS Effective Date
: 1. Original - Safety Tech. Specs.                            April 18,1980
: 2. Original - Environ. Tech. Specs.                          April 18,1980
: 3. Amendment No. 1                                          June 11, 1980
: 4. Amendment No. 2                                         August 22, 1980
: 5. Amendment No. 3                                        October 10, 1980
: 6. Order for Modification of License                      October 30, 1980
: 7. Amendment No. 4                                       December 8, 1980
: 8. Amendment No. 5                                       February 26, 1980
: 9. Amendment No. 6 (100% Power Authorization)                June 12, 1981
: 10. Amendment No. 1 (to 100% Power Author.)                    July 20, 1981
: 11. Amendment No. 2 (to 100% Power Author.)                October 15, 1981
: 12. Amendment No. 3 (to 100% Power Author.)               November 9, 1981
: 13. Amendment No, 4 (to 100% Power Author)               December 31, 1981
: 14. Amendment No. 5 (to 100% Power Author.)               February 26, 1981
: 15. Amendment No. 6 (to 100% Power Author.)                  March 29,1982
: 16. Amendment No. 7 (to 100% Power Author.)                   April 19, 1982
: 17. Amendment No. 8 (to 100% Power Author.)                    May 25, 1982
: 18. Amendment No. 9 (to 100% Power Author.)                     July 8, 1982
: 19. Amendment No. 10 (to 100% Power Author.)                   July 23, 1982
: 20. Revision to Amendment No. 8                                July 23, 1982
: 21. Amendment No. 11 (to 100% Power Author.)             September 7, 1982
: 22. Amendment No. 12 (to 100% Power Author.)               October 15, 1982
: 23. Amendment No. 13 (to 100% Power Author.)               October 18, 1982
: 24. Amendment No. 14 (to 100% Power Author.)               October 22, 1982
: 25. Amendment No. 15 (to 100% Power Author.)              December 3, 1982
: 26. Amendment No. 16 (to 100% Power Author.)             November 22, 1982
: 27. Amendment No. 17 (to 100% Power Author.)               January 27, 1983
: 28. Amendment No. 18 (to 100% Power Author.)                 March 11, 1983
: 29. Amendment No. 19 (to 100% Power Author.)                    May 5, 1983
: 30. Amendment No. 20 (to 100% Power Author.)                    May 5, 1983
: 31. Amendment No. 21 (to 100% Power Author.)                    May 5,1983
: 32. Confirmatory Order                                          May 6, 1983
: 33. Amendment No. 22 (to 100% Power Author.)             November 22, 1983
: 34. Amendment No. 23 (to 100% Power Author.)               January 27, 1984
: 35. Modification of Order                                  January 31, 1984
: 36. Confirmatory Order                                        June 12, 1984
: 37. Amendment No. 24 (to 100% Power Author.)                   July 16, 1984
: 38. Correction to Confirm. Order of 6/12/84                    July 26, 1984
: 39. Amendment No. 25                                        August 30, 1984
: 40. Amendment No. 26                                       October 15, 1984
: 41. Amendment No. 27                                       October 17, 1984
: 42. Amendment No. 28                                      December 5, 1984 1 of 8

                          .SALEM GENERATING STATION UNIT NO. 2 FACILITY OPERATING LICENSE AND TECHNICAL SPECIFICATION LIST OF AMENDMENTS Effective Date
: 43. Amendment No. 29                                          February 7, 1985
: 44. Amendment'No. 30                                         February 22,1985
: 45. Amendment No. 31                                               March 8,;1985
: 46. Amendment No. 32                                                  April 9,1985
: 47. Amendment No. 33                                                 May 13, 1985
: 48. Amendment No. 34                                                 May 17,1985
: 49. Aniendment.N6' 35                                                May,28, 1985
: 50. Amendment No!.36                                                 May,30, 1985
: 51. Amendment No. 37                                                 May 30,-1985
: 52. Amendi-nent. No. 38                                            SJunh613,-1985
: 53. Afriendmnent No. 39                                             June625, 1985
: 54. Correctionsto Amendments 28 thru 37                             June.25, 1985
: 55. AnfibndmehtrNo: 40                                      Septemb'er16, 1985
: 56. Amendhient No:'-41                                      September16,-1985
: 57. Arhendrnent No. 42                                      Septeimbe_16,1 985
: 58. Armendm 6net No. 43                                     Dec6nber30,;-.1985
: 59. A-rfen'?rent:    No. 44                                 Decenb-er 30,:1 985
: 60. A&#xfd;6en6anent No. 45                                        january 29, 1986
: 61. ,Arfiendnieht No. 46                                        1z March ,7, 1986
: 62. `Amend*nent. No. 47                                           MarchQ0101986
: 63. 'Amendment.No. 48                                            ~M rcilh --190,1:98i6
: 64.                                                                    Ap3ril 3' 0986
: 65. -M dification. tfo'.Amendment No. 46                               April 8,1986
                                                                  *..Ap'*iilfO, 198;'!_'
6
: 66. Modification, to Amendment No. 21
: 67. Ariindment No:50                                        Feb"r <March&#xfd;31,1987 2a&y26, 1987
: 68. 'Amri       l-6 hmtNo-651                                        ' Apr- 7;:1987
: 69. Arizi6eriet No 52 Am1ndent No' 53
: 70. Arriendment No 54                                          -  "Apri!l10' 1,987
: 71.                                                                  J"tne01 9,'1 987
: 72. A~r6dni'me'nt No. 55
* October 16;, 1987
: 73. Amenamefft No. 56                                       Noveo'ber-16-1987
: 74. Changes -to Amendment No. 55                            December 17z;:1987
: 75. Amendment No. 57                                                 May A2,:1988
: 76. Changes t6 Amendment No. 55                                     June 15,1988
: 77. Amendment No:. 58                                              'J.hune-27, 1988
: 78. -Armendment-No. 59                                               Jund27, 1988 2 of 8

SALEM GENERATING STATION UNIT NO. 2 FACILITY OPERATING LICENSE AND TECHNICAL SPECIFICATION LIST OF AMENDMENTS Date LCR Amendment                        Effective Date      LCR No.      Submitted
: 79. Amendment No. 60                 September 8, 1988   LCR S87-11   07/24/1987
: 80. Amendment No. 61                 August 29, 1988     LCR S88-04   05/03/1988
: 81. Amendment No. 62                 October 21, 1988    LCR S85-10   08/06/1985
: 82. Amendment No. 63                 October 14, 1988    LCR S88-12   10/10/1988
: 83. Amendment No. 64                 November 3, 1988    LCR S88-13   10/19/1988
: 84. Amendment No. 65                 January 25, 1989    LCR S87-14   01/19/1988
: 85. Amendment No. 66                 March 22, 1989      LCR S88-15   01/03/1989
: 86. Amendment No. 67                 April 24, 1989      LCR S84-22   11/27/1985
: 87. Amendment No. 68                 May 1, 1989         LCR S87-02   04/14/1987
: 88. Amendment No. 69                 May 1, 1989         LCR S82-16   01/27/1983
: 89. Amendment No. 70                 May 2, 1989         LCR S87-03   07/23/1987
: 90. Amendment No. 71                 May 2, 1989         LCR S88-11   12/20/1988
: 91. Amendment No. 72                 May 9, 1989         LCR S88-16   12/30/1988
: 92. Amendment No. 73                 April 21, 1989      LCR S89-04   04/21/1989
: 93. Amendment No. 74                 May 31, 1989        LCR S84-13   10/17/1985
: 94. Correction to Amendment No. 72   June 14, 1989
: 95. Correction to Amendment No. 52   June 16, 1989
: 96. Correction to Amendment No. 52   July 20, 1989
: 97. Amendment No. 75                 July 20, 1989       LCR S89-02   05/05/1989
: 98. Amendment No. 76                 July 31, 1989       LCR S88-07   07/15/1988
: 99. Amendment No. 77                 August 21, 1989     LCR S88-17   12/27/1988 100. Amendment No. 78                 August 28, 1989     LCR S88-02   09/12/1988 101. Amendment No. 79                 September 25, 1989  LCR S87-06   07/09/1987 102. Amendment No. 80                 September 25, 1989  LCR S88-01   06/23/1988 103. Amendment No. 81                 November 21, 1989   Letter       10/04/1989 104. Amendment No. 82                  December 4, 1989   LCR S88-08   03/23/1989 105. Replacement Page for             January 11, 1990 Amendment No. 66 106. Replacement Page for             January 11, 1990 Amendment No. 69 107. Amendment No. 83                 January 16, 1990    LCR   S89-13 10/20/1989 108. Amendment No. 84                 January 17, 1990    LCR   S89-09 09/28/1989 109. Amendment No. 85                 January 17, 1990    LCR   S89-10 09/25/1989 110. Amendment No. 86                 January 29, 1990    LCR   S88-14 12/28/1988 111. Amendment No. 87                 January 30, 1990    LCR   S88-10 09/11/1989 112. Amendment No. 88                 January 30, 1990    LCR   S89-08 09/25/1989 113. Correction to Amendment 86        February 15, 1990 114. Amendment No. 89                  March 7,1990       LCR S89-11   08/29/1989 115. Amendment No. 90                  April 20, 1990     LCR S90-02   01/04/1990 116. Replacement Page for              May 14, 1990 Amendment No. 84 117. Correction to Amendment 69        May 16, 1990 118. Amendment No. 91                  May 30, 1990       LCR   S90-09 04/04/1990 119. Amendment No. 92                  July 3, 1990       LCR   S89-07  10/17/1989 120. Amendment No. 93                  August 22, 1990    LCR   S87-07 07/27/1990 121. Amendment No. 94                  August 27, 1990    LCR   S90-01 02/22/1990 122. Amendment No. 95                  September 10, 1990 LCR   S87-10  02/23/1990 123. Amendment No. 96                  September 10, 1990 LCR   S89-12  05/21/1990 124. Amendment No. 97                  November 13, 1990  LCR   S87-15  12/24/1987 125. Amendment No. 98                  February 13, 1991  LCR   S88-09 09/13/1989 126. NRC Letter                        March 4, 1991 3 of 8

SALEM GENERATING STATION.UNIT NO. 2 FACILITY OPERATING. LICENSE AND TECHNICAL SPECIFICATION LIST OF AMENDMENTS Date LCR Amendment                             Effective Date,        A LCR No.                 Submitted 127.        Amendment No. 99                      March11, 1991,           LCR S90-04               12/27/1990 128.        Amendment No. 100.                    March 1.,11 1991         LCR S90-19               12/21/1990 129.        Amendment No. 101                     March 11, 1991           LCR S89-05              09/04/1990 130.        Amendment No. 102                     March 25;'1991           LCR S90-16              01/18/1991 131.        Amendment No. 103                     April 8;.1991            LCR S90-12               10/02/1990 132.        Amiendment No. 104                    June 5, 1991T            LCR S87-12               08/03/1987 133.        Am'dndment No. 105                    June 13,:1991            LCR S91-02               02/13/1991 134.       -miendment No. 106:                    July 1, 1991, '          LCR S90-20               02/04/1991 135.       .Amendment No. 107                     August 1, 1991           LCR S90-14-..           -11/19/1990 136.        ..Anfnldment No. 108                  August 15, 1991          LCR S91-09               06/1211991 137.        Amrfidindment No. 109                 September 5,, 1991       LCR S91              06/20/1991 138.        Amenidment No. 110                    September 17, 1991       LCR S88-06 Rev: 1        02/20/1991 139.        Amrehdmnent No. 111                   January 2, 1992          LCR S90-03               04/02/1990 140.        Anmindffient No. 112                  June 8, 1992             LCR S84-01.Rev. 2        07/07/1989 141.        Amfiendment No. 113'                  July 29, 1992            LCR S91-0l6-             05/06/1992 142.        Amendment No. 114                     August 28, 1992-         LCR S89-0I               05/12/1992 143.        Amendment No. 115                     November 9 :1992         LCR S92-0 7              07/08/1992 144.        Amendment No. 116                     January 5,' 1993:'       LCR $91-1 2              08/14/1992 145.         Arrim*6fdnent No. 117                January 5,'1993.'"       LCR S90-1 5:             08/02/1991 146.         Bases Change (Turbine                February 11; 1993 Ovb'poed Protection):-
147.       -Arfid6dffrent No. 11 8                April 21,' 1993...       LCR S91-0 3:&#xfd;          '04/24/1992
            'A"*;-en*ent No. 119.
148.                                              Ma&#xfd;,:11' 1993:,      ,   LCR S92-1 1'         -02/05/1993 149.        .       di-ent No. 120'               May 18H1993              LCR S91-0 7             01/18/1993 Augast*4;,'1993 j,,
150.         Amenedment No. 121                                            LCR S89-046i,-, .    -,&#xfd;05/411-'/1'992 151.             eA'endhrmient No. 122 Rod        Septe'm'br-22-1 9931:    LCR S93-211              (d6/17/1993 Contrl,'System USQ - No TS Page' changes 152.         Amendment No. 123                    October:4,!1993'         LCR S932011         ',':08/24/1993 153.        Amendment No. 124                     October 26, 1993         LCR S93-2:3'             08/06/993 154.    'Ani'ei-hdment No. 125                    Novembeir'16,1993        LCR S92-1 2              02/23/1993 155.   *"n*Am         lhdrhent No. 126            November,30, 1993        LCR S87-077:             03/06/1991 156.     ,&#xfd;A          l'idi&#xfd; ent No. 127.'-          December 16, 1993        LCR S92-0'4              05/26/-1992 157.         Am6hnlfient No. 128"                 January[21, 1994:        LCR S91-044 '            08/30/1993 158. - Ariedenment No. 129                        Februabb 22, 1994        LCR S92-1l 0             0.1/25/1993 159. .: Clarification Letter for Safety           April 41:1994 Evaluation Amendment 126 160.         And6h ment No. 130;                  April 17, 1994           LCR S91-0(6 :*           06/20/1' 991
:,Ahendidnient No.
161.                               13.1           May 4, 1994"        '    LCR S93-0 2              04/28/1993 162.         Amendment No. 132                    July 20, 1994            LCR S93-1 5              08/06/1993 163.         Amendment No. 133                    July 20, 1994            LCR S93-1 7-             06/11/1993 164.         Amendment No. 134                    July.27, 1994"           LCR S94-0l8.05/03/1994 165.         Awdn~hdhent No. 135 '          ,     August 22, 1994;'.       LCR S94-077'            03/03/1994 166.       "Afeirdmnent No. 136 .                 September 8,:1994        LCR S94-1 7 -           07/13/1994 167.      'Arh6iinent No. 137                     September 8, 1994"       LCR S94-0*53            04/12/i994 168.         Am6&dment No. 138                    September 8, 1994        LCR S94-1 1 -           05/18/1994 4 of 8

SALEM GENERATING STATION UNIT NO. 2 FACILITY OPERATING LICENSE AND TECHNICAL SPECIFICATION LIST OF AMENDMENTS Date LCR Amendment                           Effective Date     LCR No. Submitted 169. Amendment No. 139                   October 20, 1994   LCR S94-09 03/28/1994 170. Amendment No. 140                   November 4, 1994   LCR S94-18 08/19/1994 171. Amendment No. 141                   November 8, 1994   LCR S94-14 06/14/1994 172. Amendment No. 142                   December 12,1994   LCR S94-21 09/09/1994 173. Amendment No. 143                   December 14, 1994  LCR S93-10 03/28/1994 174. Bases Change (RCS                   December 22, 1994 Overpressure Protection) 175. Amendment No. 144                   December 27, 1994  LCR S94-29 09/29/1994 176. Amendment No. 145                   March 16, 1995     LCR S93-08 04/16/1993 (Control Air System USQ - NO TS Page Changes) 177. Amendment No. 146                   April 17,1995      LCR S94-19 09/20/1994 178. Amendment No. 147                   April 17,1995      LCR S94-06 02/03/1994 179. Amendment No. 148                   May 3, 1995        LCR S94-30 08/30/1994 180. Amendment No. 149                   May 22, 1995       LCR S94-25 09/29/1994 181. Amendment No. 150                   June 6, 1995       LCR S94-46 02/09/1995 182. Amendment No. 151                   June 12, 1995      LCR S93-19 11/18/1994 183. Amendment No. 152                   June 20, 1995      LCR S94-15 06/29/1994 184. Amendment No. 153                   August 1, 1995     LCR 394-28 04/18/1995 185. Amendment No. 154                   August 7, 1995     LCR S92-14 02/05/1993 186. Amendment No. 155                   August 24, 1995    LCR S94-33 12/23/1994 187. Amendment No. 156                   September 6, 1995  LCR S94-35 05/02/1995 188. Amendment No. 157                   September 18, 1995 LCR S93-06 09/20/1994 189. Amendment No. 158                   September 19, 1995 LCR 393-27 01/21/1994 190. Amendment No. 159                   October 30, 1995   LCR S94-45 03/30/1995 191. Amendment No. 160                   January 24, 1996   LCR S93-28  10/11/1994 192. Amendment No. 161                   February 22, 1996  LCR S95-05 09/28/1995 193. Amendment No. 162                   March 11, 1996     LCR S94-10 04/13/1994 194. Bases Change (Containment           March 14,1996 Penetration Overcurrent Protection) 195. Amendment No. 163                   April 29, 1996     LCR S95-15 01/04/1996 196. Amendment No. 164                   June 27, 1996      LCR S96-01 02/06/1996 197. Amendment No. 165                   July 10, 1996      LCR S96-05 05/07/1996 198. Amendment No. 166                   July 11, 1996      LCR S96-04 04/22/1996 199. Amendment No. 167                   November 4, 1996   LCR S96-09 07/12/1996 200. Bases Change (R41 Radiation         December 5, 1996 Monitor) 201. Amendment No. 168                   December 12, 1996  LCR S96-14 09/20/1996 202. Amendment No. 169                   December 17, 1996  LCR S96-11 08/27/1996 203. Amendment No. 170                   January 17, 1997   LCR S96-12  10/01/1996 204. Amendment No. 171                   January 23, 1997   LCR S96-15  10/24/1996 205. Amendment No. 172                   January 30, 1997   LCR S95-02 09/25/1996 206. Amendment No. 173                   February 6, 1997   LCR S95-21 06/10/1996 207. Amendment No. 174                   February 6, 1997   LCR S96-03 05/31/1996 208. Amendment No. 175                   March 21, 1997     LCR S95-13 01/11/1996 5 of 8

SALEM GENERATING STATION UNIT NO. 2 FACILITY OPERATING LICENSE AND TECHNICAL SPECIFICATION LIST'OF AMENDMENTS Date LCR Amendment                           Effective Date,           LCR No.        Submitted 209.,      Amendment No. 176                   May 8, 1997,              LCR S96-19     01/07/1997 210.       Amrenidment No. 177                 June 4,,-1997             LCR S97-03     01/31/1997 211.       Amendnent No. 178                   June 13,1997              LCR S95-09     01/31/1997 212.       Amendment No. 179                   June 19;'1997             LCR $96-13. 10/25/.1996 213.        Amendment No. 180                  June 24, 1997             LCR S95-10     04/11/1997 214.        Amendment No. 181                  July 17, .1997            LCR S96-06     06/18/1996 215.        Amendment No. 182                  July 29, 1997             LCR S97-05. 02/11/1997 216.        Bases.Change (Movable              August 13, 1997, Cohtr01 Assemblies)',,
217.        Bases Change (Component            March 7, 1997 Cooling Water) 218.        Amendment No. 183-                 September 10, 1997        LCR S97-19     08/19/1997 219.        Amendment No. 184                  September 11, 1997        LCR S97-11     04/25/1997 220.    . Amendment No. 185                    January 8, 1998           LCR S97-18      11/04/1997 221.        Aniendment No. 186                 January 29,1998.          LCR S97-14      10/24/1997 222.        Amendment No. 187                  January 29, 1998          LCR S95-19      10/21/1997 223.        Amendment No. 188                  February 27, 1998         LCR S97-27      12/15/1997 224.       'Anepmlment No. 189-                 March 12,19980           LCR S95-37     03/04/1997 225.   ,<,Am'ndment No. 190'-.                  March 19.1998            LCR S97-21V     10/29/1997 226.   . Amendment No. 191.                     March 24;A1998           LCR S96-20:  .- 11/04/1997 227.        B*sB ssChanges (Sump ph,           April 29;"'i1998, Re;'fdelihg Canal Samplirg) 228.  *,:'A6'd6hdmnent No. 192                 July; 14, 1998,-      ,*. LCR S95-23'. 09/28/1995 229.        Ba'&sect;ks Change (Pow~r.              Septetrnb424;.1998 Raig3b Negative Fluk Trip) 230.  '-*;'Ame6ndmheht No. 193.      ,         AugustU6&l 9,98.,,-:*. LCR S97-17"    11Ii/14/1997 231.  `: Amendment No. 194,                     Sept6 ber.80,1998        LCR S95-08     06/2211995 232.  :,+Bases Change (RWSTriihimum            Januaryr19, 1999;. J level) and License Condition Change (authorized power level) 233.       A*fidndment No. 195                  December'2; 1998         LCR S98-03     08/12/1998 234.        Am endment No. 196.'                Decembe, ,18, 1998,      LCR S97-04&#xfd;    .08/01/1997 235.        Arnbhdment No. 197.                January 8,A999 -          LCR S94-41'    05/10/1996 236.        Amend,0mfent No. 198..              February 1 "1999         LCR S97-30i     10/12/1998 09/29/19&sect;98 237.      ,mendhnent No. 199                    February 26&1999         LCR S98-11 238.        Amendment No. 200                   March 23&#xfd; 1999           LOR S95136     09/25/1996 239.        Amendment No. 201                   March 24, 1999           LCR S95-34     09/177l 998 240.        Aniendment No. 202 -1.             April 26,'1999i.          LCR &sect;98-16     02/08/1999 241.     -'Afmh6dment No. 203                  April30, 1999             LCR S95-18     03/26/1998 242.        An-i'rhidment No. 204              July 21 ,',1999 ,         LCR S98-17     02/02/1999 243.      :,
          "*,, nndment No. 205                  September 14; 1999       LCR S98-02     07/02/1999 244.        Aninrfi*ient No. 206                November2, 1999          LCR S97-08':    11/1411997 245.        Amendtment No. 207                 JanuarY24, 2000           LCR S99-07'    08/25/1999 246.        A*riAndment No. 208                 February 29, 2000        LCR S99-02     07/29/1999 247.        Amrendment No. 209                  March 21 2000            LCR S95-44     10/24/1997 248.        Amendment No. 210                   March 30, 2000           LCR S98-13     07/23/1999 249.        Amendment No. 211                  June 14, 2000             LCR S99-05     04/14/1999 250.        Amendment No. 212                  July 25, 2000             LCR S99-15     04/10/2000 251.        Amendment No. 213                  August 17, 2000           LCR SOO-04     04/13/2000 252.        Amendment No. 214                  August 21, 2000           LCR S99-14     08/11/2000 6 of 8

SALEM GENERATING STATION UNIT NO. 2 FACILITY OPERATING LICENSE AND TECHNICAL SPECIFICATION LIST OF AMENDMENTS Date LCR Amendment                      Effective Date     LCR No.           Submitted 253. Amendment No. 215              August 24, 2000    LCR S99-19        01/24/2000 254. Amendment No. 216              October 2, 2000    LCR SOO-01        03/02/2000 255. Amendment No. 217              October 2, 2000    LCR SOO-02        03/13/2000 256. Amendment No. 218              November 6, 2000   LCR SOO-08        06/14/2000 257. Amendment No. 219              December 5, 2000   LCR S99-16        02/07/2000 258. Amendment No. 220              December 19, 2000  LCR S99-11        12/29/1999 259. Amendment No. 221              December 29, 2000  LCR S99-23        12/20/1999 260. Amendment No. 222              January 12, 2001   LCR S99-22        12/20/1999 261. Amendment No. 223              April 2, 2001      LCR SOO-03        05/15/2000 262. Amendment No. 224              May 25, 2001       LCR SOO-06        11/10/2000 263. Amendment No. 225              September 19, 2001 LCR S99-13        09/26/2000 264. Amendment No. 226              September 19, 2001 LCR S99-21 Rev. 1 05/31/2000 265. Amendment No. 227              October 18, 2001   LCR S99-23        12/20/1999 266. Amendment No. 228              December 17, 2001  LCR SOO-09        01/05/2001 267. Amendment No. 229              January 4, 2002    LCR S99-12        04/16/2001 268. Bases Change (POPS)            September 12, 2001 LCR S00-09B       09/27/2000 269. Bases Change (MSIVs)           September 12, 2001 LCR S01-03B       03/09/2001 270. Bases (Group Demand Counters)  September 12, 2001 LCR S01-07B       08/02/2001 271. Amendment No. 230              February 22, 2002  LCR S01-01        03/05/2001 272. Amendment No. 231              June 3, 2002       LCR S02-01        01/17/2002 273. Amendment No. 232              October 10, 2002   LCR S02-03        06/28/2002 274. Amendment No. 233              October 10, 2002   LCR S02-04        07/18/2002 275. Amendment No. 234              October 11, 2002   LCR SO1-02        11/01/2001 276. Amendment No. 235              November 5, 2002   LCR S01-05        08/17/2001 277. Amendment No. 236              April 10, 2003     LCR S02-13        10/23/2002 278. Amendment No. 237              April 16, 2003     LCR S02-02        07/25/2002 279. Amendment No. 238              June 13, 2003      LCR S02-08        09/26/2002 280. Bases Change (MSIVs and        June 19, 2003      LCR S02-11 B      01/24/2003 Fuel Decay Time) 281. Amendment No. 239              June 26, 2003      LCR S03-01        01/29/2003 282. Amendment No. 240              October 1,2003     LCR S03-02        04/10/2003 283. Amendment No. 241              October 28, 2003   LCR S02-07        04/11/2003 284. Amendment No. 242              January 7, 2004    LCR S03-08        07/01/2003 285. Bases Change (AC Sources)      March 5, 2004      LCR S03-096       3/5/2004*
286. Amendment No. 243              January 29, 2004   LCR S03-03        06/06/2003 287. Amendment No. 244              February 6, 2004   LCR S02-012       02/14/2003 288. Amendment No. 245              September 16, 2004 LCR S02-010       07/29/2002 289. Amendment No. 246              April 1,2005       LCR S04-06        07/23/2004 290. Amendment No. 247              September 9, 2005  LCR S04-03        09/27/2004 291. Amendment No. 248              September 30, 2005 LCR S03-07        08/11/2005 292. Amendment No. 249              October 14, 2005   LCR S03-06        03/04/2005 293. Amendment No. 250              January 11, 2006   LCR S04-08        02/15/2005 294. Amendment No. 251              January 11, 2006   LCR S04-10        01/11/2005 295. Amendment No. 252              February 17, 2006  LCR S03-05        04/26/2004 296. Amendment No. 253              May 25, 2006       LCR S05-06        08/31/2005 297  Amendment No. 254              July 28, 2006      LCR S05-01        02/10/2005 298  Amendment No. 255              October 26, 2006   LCR S05-08        09/26/2005 299  Amendment No. 256              September 28, 2006 LCR S05-07        09/21/2005 300  Amendment No. 257               October 13, 2006  LCR S05-09        12/07/2005 301  Amendment No. 258               October 28, 2006  LCR S06-04        04/25/2006 7 of 8

SALEM GENERATING STATION UNITNO. 2 FACILITY OPERATING LICENSE AND TECHNICAL SPECIFICATION LIST OF AMENDMENTS Date Amendment Amendment                        Effective Date     LCR No.       Irnplemented 302    Amendment No. 259                    March 7, 2007      LCR S06-15      04/21/2008 303     Amendrnent No. 260                  March 19, 2007     LCR S06-06      04108/2007 304     Amen dment No. 261                  March 19, 2007     LCR S04-09      05/17/2007 305     Amendment No. 262                   March 29, 2007     LCR S06-01      05/29/2007 306    Amendhment No. 263                   April 19, 200,7    LCR S06-03      05/18/2007 307     Amendment No. 264                   April 19, 2007     LCR S06-05      06/18/2007 308    An,'endm'ent No. 265                 June 6, 2007       LCR S05-12      08/02/2007 309     NR0C LCetter 08/09/2007             August 09, 2007    Order B.5.b     08/28/2007 310     Am&deg;e'ndment No. 266                 June 19, 2007      LCR S05-04      096/17'/2007 311     Amerndment No. 267                  August 23, 2007    LCR S06-02      04/16/2008 312     Amendment No. 268                   November 15, 2007  LAR S07-05      12/26/2007 313     Amendment No. 269                   January 24, 2008'  LAR S0702       07/22/2008 314     Amendment No. 270                   February 27, 2008  LCR S06-10      03/24/2008 315    Amendment No. 271                    March 5, 2008      LAR S07-06      03/07/2008 316     Armendment No. 272                  March 13, 2008     LAR S08-03      03/13/2008 317     B*es 'Change S2008-084*             April 14, 2008     S20082-84'      04/14/2008 318     Base'dChange S2008-089"             April 21, 2008     S2008-089       04/21/2008 319    Arr!6..rdi'ent No. 273               September 24; 2008 LAR S08-01      10/06/2008 320        erlendffent No. 274              May 14, 20097      LAR S08-04      09/28/2009 321      ,bndient No. 275'                  June 2, 2Q09 . LAR S08-05    ,06/30/'2009 322    Amnene'd'ment No. 276                January 12;2010    LAR S09-01 323    AmXe'ndment No. 277-                 February"17, 2010  LAR S08-06      03/,12/2010 324     BIasqes"C`hange S20107119*!         June 30, 2010... S2010-119       07/260/2010 325    kriimridnent       No. 278,'.        June 15, 2010      LAR S09-03      08/03/2010
       )&#xfd;       ffn'i*ent No. 279*',                                          '10/`,04/2b10o 326                                         August 20, 20101   LAR S09-06 Amendment No. 28'0                                                      09/02/2010 327    Amendment No. 281                    September 01, 2010 LAR Si0-"03-'
328    A meridhent No. 280                  December 15, 2010  LAR S 10-02     02/10/261 329    Ar"*ndment No. 282            "                         LAR S10-01 March 21, 2011                     06/07/2011 330     RenIewed License DPR-75             June 30,2011 2011     NA              07/1,3/2011 July 28, 331    Ariendment No. 283                                      LAR S09-08      08/17/1211 332    Amend*-dent No. 284.                 August 25, 2011    LAR S 10-04     10/14/2011 333     Bases change S201 1238*             November 28, 2011  S2011-238       03/07/2012
* Implemented under TS Bases Control Program 8 of 8

PSEG NUCLEAR LLC EXELON GENERATION COMPANY, LLC DOCKET NO. 50-311 SALEM NUCLEAR GENERATING STATION, UNIT NO. 2 FACILITY OPERATING LICENSE Renewed License No. DPR-75
: 1. The Nuclear Regulatory Commission (the Commission) having found that:
A. The application for a renewed license, filed by PSEG Nuclear LLC acting on its own behalf and as agent for Exelon Generation Company, LLC (the licensees), complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's regulations set forth in 10 CFR Chapter I and all required notifications to other agencies or bodies have been duly made; B. Construction of the Salem Nuclear Generating Station, Unit No. 2 (facility) has been substantially completed in conformity with Construction Permit No. CPPR-53 and the application, as amended, the provisions of the Act and the regulations of the Commission; C. The facility will operate in conformity with the application, as amended, the provisions of the Act, and the regulations of the Commission; D. There is reasonable assurance: (i) that the activities authorized by this renewed operating license can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations set forth in 10 CFR Chapter I; E. PSEG Nuclear LLC is technically qualified to engage in the activities authorized by this renewed operating license in accordance with the Commission's regulations set forth in 10 CFR Chapter I; F. The licensees are financially qualified to engage in the activities authorized by this renewed license in accordance with the Commission's regulations set forth in 10 CFR Chapter I; G. The licensees have satisfied the applicable provisions of 10 CFR Part 140, "Financial Protection Requirements and Indemnity Agreements," of the Commission's regulations; H. The issuance of this renewed operating license will not be inimical to the common defense and security or to the health and safety of the public;
: 1. After weighing the environmental, economic, technical and other benefits of the facility against environmental and other costs and considering available alternatives, the issuance of Renewed Facility Operating License No. DPR-75 subject to the conditions Renewed License No. DPR-75

for protection of the environment set forth herein is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied; J. The receipt, possession, and use of source, byproduct and special nuclear material as authorized by thisreiiewed licejise will be in accordance with theCommission's regulations in 10 CFR Parts 30, 40 and 70; and K. Actions have been identified and have been or will be taken with respect to (1) managing the effects of aging duringthe" period of exter~ded operation on the functionality of structures and components that have been identified to require review under 10 CFR 54:21 (a)(1),.&#xfd;and ,(2) timehlimited aging analyses ,that',have'been identifiedto require review under 10 CFR 54.21 (c), such that there is reasonable assurance that the activities;authorized by this rnhe-wed operating&#xfd; licen6e will conti6ue'to be conducted in accordance with the currehtlicensing basis;, as defined in 10 CFR,54.3, for the facility, and thatany changes mbade to th6 facility's- current' licenslng ba'sis ih order'-to comply with 10 CFR 54.29(a) ard in kccordahce with the Act and the Corn'missian's regulations.
: 2. Pursuant to approval by the Nuclear Regulatory Commission at meetings on Janbar&#xfd;y,14, 1 9 8 11,;April 28,-:.1981, an'd May 19,"1-981:* the' Lice'nse fo-r Fu61-L`dadirig and&
LovP            e      issud     on Ai'ri118, 19808is siupersedd bV Rehe**6d Fa6ilit&#xfd;' Operating License No.&#xfd; DPR-75'lerebV is&sect;*0ed, t6 PSEG NulceIr.LLC, a'rnd tothe           ExelorGenfieration read  as f6llW        :
licensees),
Company LLC (Exelon Generation Company), (the A. Thi&#xfd; renbewedhicense applies to the"Salem Nu'clear Generating Station,' 0nit No6. 2, -
pressurized water nuclear reactor ard"' s*6iat{dc 6e'ip0ffi:e(the fdility),"own~d by the licensees. The facility is located on the southern end of Artificial Island on the east bank of.the D61awviare*.FRiV-er ih'(&#xfd;0'w6ia*T                         i iri S'&Cleren"CodLnty, Nl*pw Jersey ald isldescribed. in the.Firn'al "Safety AhAIys;ih                upplemtedand iaheinded and asi**ort'sd the n ronheport-as                  su1Rppemented and amended.'
B. Subject to the conditions and requirements incorporated herein, the Commission hereby (1)    PSEG Nuclear LLC, and the Exelon Generation Company to0possessthe facility at the designated location in Salem County, New Jersey, in accordance with the pr6ceduresand limrtrot6nis set forth in the renewed lcense;.
(2)    PSEG Nuclear LLC, pursuant to Section 104b of the Act and 10 CFR'part' 50, "Domestic Licensing of Production and Utilization Facilities," to possess, use and poperate the'faci"ty at thte` designated Iocation n Salem, County New,Jersey, in accordah&e with the lirfiititio-ns~iet forth:in~this rene'ved liceiis;,
(3)    PSEG NlblebicrtLCr 'pu'r unt ffo the Act. ani.d 10 CFR Parit 70, to redeive; possess and use at any!           specia nuclear, material as-reacttr ful; in accordance with the limitations for storage and amounts required for reactor operation, as described in the Final Safety Analysis Rbport,'as su"pplemented'and'a'mIended; Renewed License No. DPR-75

(4)    PSEG Nuclear LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess and use at any time any byproduct, source or special nuclear material as sealed neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration and as fission detectors in amounts as required; (5)    PSEG Nuclear LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess and use in amounts as required any byproduct, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and (6)    PSEG Nuclear LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to possess but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility.
C. This renewed license shall be deemed to contain and is subject to the conditions specified in the Commission's regulations set forth in 10 CFR Chapter i and is subject to all applicable provisions of the Act and to the rules, regulations and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:
(1)    Maximum Power Level PSEG Nuclear LLC is authorized to operate the facility at steady state reactor core power levels not in excess of 3459 megawatts (thermal).
(2)    Technical Specifications and Environmental Protection Plan I
The Technical Specifications contained in Appendix A, as revised through Amendment No. 284, and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the renewed license. PSEG Nuclear LLC shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.
Renewed License No. DPR-75 Amendment No. 284

PAGE INTENTIONALLY BLANK ITEMS 3 THROUGH 9 DELETED Renewed License No. DPR-75

(10) Fire Protection PSEG Nuclear LLC shall implement and maintain in effect all provisions of the approved fire protection program as described in the Updated Final Safety Analysis Report, as approved in the NRC Safety Evaluation Report, dated November 20, 1979, and in its supplements, and in the NRC Safety Evaluation dated January 7, 2004, subject to the following provision:
PSEG Nuclear LLC may make changes to the approved fire protection program without prior approval of the Commission only if those changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire.
Renewed License No. DPR-75

PAGE INTENTIONALLY BLANK ITEMS 11 THROUGH 25 DELETED Renewed License No. DPR-75

(26) Additional Conditions The Additional Conditions contained in Appendix C, as revised through Amendment No. 227 are hereby incorporated into this renewed license. PSEG Nuclear LLC shall operate the facility in accordance with the Additional Conditions.
(27) PSE&G TO PSEG Nuclear LLC License Transfer Conditions
: a. PSEG Nuclear LLC shall take all necessary steps to ensure that the decommissioning trust is maintained in accordance with the application, the requirements of the Order Approving Transfer of License and Conforming Amendment, dated February 16, 2000, and the related Safety Evaluation dated February 16, 2000.
: b. The decommissioning trust agreement shall provide that:
: 1. The use of assets in both the qualified and non-qualified funds shall be limited to expenses related to decommissioning of the unit as defined by the NRC in its regulations and issuances, and as provided in the unit's renewed license and any amendments thereto. However, upon completion of decommissioning, as defined above, the assets may be used for any purpose authorized by law.
: 2. Investments in the securities or other obligations of PSE&G or affiliates thereof, or their successors or assigns, shall be prohibited. In addition, except for investments tied to market indexes or other non-nuclear sector mutual funds, investments in any entity owning one or more nuclear power plants shall be prohibited.
: 3. No disbursements or payments from the trust shall be made by the trustee until the trustee has first given the NRC 30 days notice of the payment. In addition, no disbursements or payments from the trust shall be made if the trustee receives prior written notice of objection from the Director, Office of Nuclear Reactor Regulation.
: 4. The trust agreement shall not be modified in any material respect without prior written notification to the Director, Office of Nuclear Reactor Regulation.
: 5. The trustee, investment advisor, or anyone else directing the investments made in the trust shall adhere to a "prudent investor" standard, as specified in 18 CFR 35.32(3) of the Federal Energy Regulatory Commission's regulations.
: c. PSEG Nuclear LLC shall not take any action that would cause PSEG Power LLC or its parent companies to void, cancel, or diminish the commitment to Renewed License No. DPR-75

fund an extended plant shutdown as represented in the application for approval of the transfer of this license from PSE&G to PSEG Nuclear LLC.
(28) Exelon Generation Company shall provide tothe Director of the Office of Nuclear
      -Reactor Regulation a copy~of any:application,:at the'time'it is filed,%to transfer (excluding grants of security interests or liens) from Exelon Generation Company to its direct.o.r.'indirect parent,. or. to any other affiliatedcdmp6n6y., facilities for the production, transmission, or distribution of electric energy having a depreciated book value exceeding, ten-percent- (10%) of Exelon Generatisn Company's P,consolidated netutility plant, as recorded on Exelon Generation Company's books ofaccount (29) Exelon Generation Company shall have decommissioning trust funds for Salem, Unit 2, in the following minimum amount on the closing date of the license transfer to it:
Salem,,Unit 2                      $45,059,302 (30)' The-decommissioning trust agreement for. Salem,- Unhit 2, shall be subject to the following:.r,
: a. The decommissioning trustfagreement must be in aJform acceptable to the NRC.
: b. With,.respectto ,the decommissioqing,&#xfd;trust fund, investments in the securities or other obligations of ExelonCorporation oraffili'aes thereof; or their succesos orsassigns are. prohibited. Except for!ninvestments tied to market indexes or other.no'n-huclear &#xfd;ector. mutual funds,;: inVestments in any entity owning one or more nuclear power plants are prohibited.
: c. The de&commissioning..trbst~agreement for'Salem, Unit 2, must provide that no disburse ments or payments:from the trust'shall'b e made by the trustee unless the trustee has first given the Director, Office'of Nuclear Reactor Regulation, 30 days prior.writtteh notice of payment. The decommissioning trust agreement shall further contain a provision that no disbursements or payments frorni theetrust shall: be 'made if.the trdstee receives prior written notice'ofobj'ction fomthe 'NRC.
: d. The decommissioning trust agreement must provide that the agreement can not be amended in any material respect without-pribr, Witten consent of the Director;-'Office of Nuclear Reactor- Regolation..
: e. The appropriate section of the decommissioning trusta6greement shall state that the trustee, investment advisor, or anyone else directing the investments maderinrthe trust'shall adhere to a "prudent investor:' stf'hdard, as specified in 18 CFR 35,.32(a)(3) of the Federal Energy Regulatory Commission's regulations.
Renewed License No. DPR-75

(31)  Exelon Generation Company shall take all necessary steps to ensure that the decommissioning trust is maintained in accordance with the application for approval of the transfer of its ownership interest in Salem, Unit 2, license and the requirements of the Order approving the transfer, and consistent with the safety evaluation supporting the Order.
(32) Mitigation Strategy The licensee shall develop and maintain strategies for addressing large fires and explosions and that include the following key areas:
: a. Fire fighting response strategy with the following elements:
: 1. Pre-defined coordinated fire response strategy and guidance
: 2. Assessment of mutual aid fire fighting assets
: 3. Designated staging areas for equipment and materials
: 4. Command and control
: 5. Training of response personnel
: b. Operations to mitigate fuel damage considering the following:
: 1. Protection and use of personnel assets
: 2. Communications
: 3. Minimizing fire spread
: 4. Procedures for implementing integrated fire response strategy
: 5. Identification of readily-available pre-staged equipment
: 6. Training on integrated fire response strategy
: 7. Spent fuel pool mitigation measures
: c. Actions to minimize release to include consideration of:
: 1. Water spray scrubbing
: 2. Dose to onsite responders (33) Upon implementation of Amendment No. 269 adopting TSTF-448, Revision 3, the determination of control room envelope (CRE) unfiltered air inleakage as required by SR 4.7.6.2, in accordance with TS 6.17.c.(i), the assessment of CRE habitability as required by Specification 6.17.c. (ii), and the measurement of CRE pressure as required by Specification 6.17.d, shall be considered met. Following implementation:
: a. The first performance of SR 4.7.6.2, in accordance with Specification 6.17.c.(i), shall be within the specified frequency of 6 years, plus the 18 month allowance of SR 4.0.2, as measured from June 4, 2003, the date of the most recent successful tracer gas test, as stated in the December 9, 2003 letter response to Generic Letter 2003-01, or within the Renewed License No. DPR-75

next 18 months ifthe time period since the most recent successful tracer gas test is greater than 6 years.
: b. The first performance of the periodic assessment of CRE habitability, Specification 6.17.c(ii), shall be 3 years, plus the'9 month allowance of SR 4.0.2, as measured from June 4, 2003, the date of the most recent successful tracer gas test, as stated in the DecemberK9, 2003.letter response to Generic Letter 2003-01, or within the next 9 months if the time period since the most recent successful tracer gas test is-greater than 3 years.
: c. The first performance of the periodic measurement of CRE pressure, Specification 6.17.d, shall be within"18 months; plus the 138 days allowed by SR 4.0.2, as measured from September 22, 2005, the date of the most recent successful pressure measurement test, or within 138 days if not performed previously..-
(34) PSEG Nuclear LLC may make changes to the prograims arid activities described in the UFSAR supplement, submitted pursuant to,10 CFR-54&#xfd;21 (d), as revised during the license renewal application review process, provided PSEG Nuclear LLC evalUaties such"t*hanges'&#xfd;pu-rsLant to'the'criteria' Set forth in 10 CFR 50.59 and otherwise complies with the requirements in that section.
(35) Appendix A of NUREG-21 01, "Safety Evaluation Re~pobt Re ated -to the License Renewal of Salem Nuclear Generating.Station/7ii'datedCin6 2011, and PSEG Nuclear LLCrUFSAR'supplement s&#xfd;ubmitted- pufrsuant to,'*;10 CFR 54.21 (d), as revised on Maiy 18, 201.1, 'desci'c're ceri      fut"ire progfams' and activities to be completed before the period of ext'ended opelation., PSEG Nuclear LLC shall complete these activitiesrio later than Apiril1 8-2020;.drI s&#xfd;hall notify the NRC in writing when implementation of these activities is complete.
(36) All capsules in the reactor vessel that are removed and tested must meet the test procedures and reporting requirements&#xfd;of AmericanSdociety for Testing and Materials (ASTM) E 185-82 to the betent practicable for the6,configuration of the specimens in the capsule. Any changes to the capsule withdrawal schedule, inc1luding Sp"*re a'pules, m'ust b*&   :A-5'6p  d by the ,NRC p-ri- to implem"6     tation.
All caps'ules-placed~in' st6'rage'rmjst-,b1e5'miaint'ained foi futrirhds'ertidn'. Any changes to storgerequirerments'must&#xfd; bkalproved by th& NRC-`kChainges to the w.ithd rwal s-che'du(ile"oi.stod.age',requirementsshall be'sul mitted to the NRC as a repiort irn'accordarince with 10 CFR 50.4.
D. An exemption from certain requirements of Appendix J to 10 CFR Part 50 is described in the Office of Nuclear Reactor Regulatib'n's Safety Evaluation Report, Supplement No. 4.
This e6emptionhwas-&#xfd;athoiized'by IaWhand Will not endanger life-'&P6bperty or the common~defensehnd security and is!otherwise in thb, public interest; The exemption, therefore, remirins in effect.- Thegrantingiof the exemiption was authorized with the Renewed License No. DPR-75

issuance of the License for Fuel-Loading and Low-Power Testing, dated April 18, 1980.
The facility will operate, to the extent authorized herein, in conformity with the application as amended, the provisions of the Act, and the regulations of the Commission.
E. The licensee shall fully implement and maintain in effect all provisions of the Commission-approved physical security, training and qualification, and safeguards contingency plans including amendments made pursuant to provisions of the Miscellaneous Amendments and Search Requirements revisions to 10 CFR 73.55 (51 FR 27817 and 27822) and to the authority of 10 CFR 50.90 and 10 CFR 50.54 (p).
The plans, submitted by letter dated May 19, 2006, are entitled: "Salem-Hope Creek
   .Nuclear Generating Station Security Plan," "Salem-Hope Creek Nuclear Generating Station Security Training and Qualification Plan," and "Salem-Hope Creek Nuclear Generating Station Security Contingency Plan." The plans Contain Safeguards Information protected under 10 CFR 73.21.
PSEG Nuclear LLC shall fully implement and maintain in effect all provisions of the Comrrission-approved Cyber Security Plan (CSP), including changes made pursuant to the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The Salem-Hope Creek CSP was approved by License Amendment No. 283.
F. A temporary exemption from General Design Criterion 57 found in Appendix A to 10 CFR Part 50 is described in the Office of Nuclear Reactor Regulation's Safety Evaluation Report, Supplement No. 5, Section 6.2.3.1. This Exemption is authorized by law and will not endanger life or property or the common defense and security and is otherwise in the public interest. The exemption, therefore, is hereby granted and shall remain in effect through the first refueling outage as discussed in Section 6.2.3.1 of Supplement 5 to the Safety Evaluation Report. The granting of the exemption is authorized with the issuance of the Facility Operating License, dated May 20, 1981. The facility will operate, to the extent authorized herein, in conformity with the application as amended, the provisions of the Act, and the regulations of the Commission.
G. This renewed license is subject to the following additional condition for the protection of the environment:
Before engaging in additional construction or operational activities which may result in an environmental impact that was not evaluated by the Commission, PSEG Nuclear LLC shall prepare and record an environmental evaluation of such activity. When the evaluation indicates that such activity may result in a 'significant adverse environmental impact that was not evaluated, or that is significantly greater than that evaluated in the Final Environmental Statement or any addendum thereto, PSEG Nuclear LLC shall provide a written evaluation of such activities and obtain prior approval from the Director of Nuclear Reactor Regulation.
H. If PSEG Nuclear LLC plans to remove or to make significant changes in the normal operation of equipment that controls the amount of radioactivity in effluents from the Salem Nuclear Generation Station, the NRC shall be notified in writing regardless of whether the change affects the amount of radioactivity in effluents.
DELETED Renewed License No. DPR-75 Amendment No. 283

J. The licensees shall immediately notify ilte Commission of any accident at this facility which could result in an unplanned release of quantities 'f fission products in excess of allowable limits for normal operation established by the Commission.
K. The licensees shall have and mainrtain financial prote'ction .of such ty~e and in'such amounts as the Commissiohnshall require in.accordance with Section 170 of the Atomic Energy Act of 1'954, as amended to cover public.liability clairhis.
L. The licens'e is authorized ti defer certain eighteen-moi6th surveillance items from the dates req~ired' by Techniial Sp .ecifications 40.2(ai),ahd 4,7.1002(c). The'sSu"rveillances sha be completed prior to startup following the first refuling outage. The' rwisions of Technical Specifications 4.0.2(b) and ,4.7.10.2(c) are not changed. _The affected items are identified in the Safety Evaluation accompa'nying Amendment No. 14 issued October 22, 1982 and this license change.               .
M. This. renewed licenselis effective as of the date of the issuance and shall expire at midnight Ap:rii 18, 2040.            .
N. RELOCATED TECHNICAL SPECIFICATIONS P SEG NuclearLLC shall relocate certain'technical sp"cifiation requirementsto liiensee-controll6'd documents as deScribed below. The location'of these rie'uirements shall bebret6nied by theihcensee   s. ....                             .
: a.     *T'his license' condition a            es thobostelcatio'n of. certainY technical specifi`cation requirements to icensene-controlleddocuments (FAR), bas"described in the licensee' sa pphcations Wit the' staff's safetyVevaluatio approval, and Amendment Nb. as noted belIoVV     '         ',
Licensee's Application, Safety Evaluations               Amendment Nos.
S&#xfd;eptember 25, 1996          January 30, 1997             172 Renewed License No. DPR-75

Implementation shall include the relocation of technical specifications requirements to the appropriate licensee-controlled document as identified in the licensee's application.
FOR THE NUCLEAR REGULATORY COMMISSION IRA!
Eric J. Leeds, Director Office of Nuclear Reactor Regulation Attachments:
: 1. Appendix A - Technical Specifications
: 2. Appendix B - Environmental Protection Plan
: 3. Appendix C - Additional Conditions Date of Issuance: June 30, 2011 Renewed License No. DPR-75

INDEX DEFINITIONS SECTION                                                                                                                                                PAGE 1.0    DEFINITIONS DEFINED TERMS ..........                                      ..........                . . ..       .. &deg;.   . . . .. . . . . . . . . . . o.o..
ACTION .................
AXIAL FLUX DIFFERENCE                                         ..........                 * .'. .o.&deg;&deg; '
CHANNEL CALIBRATION                                                                                        ..... .. &deg; . .. .'.. .o ..D* . .--. .
                                                                                                                                           . .. . .1-.
                                                                    ..........                 . ...........                .............                1-1 CHANNEL CHECK ...........................
CHM EL :UNCTIO.6u~                 TES.T ..........................................                                                                1-1 CONTAINMENT INTEGRITY ............................................                                                                                 1-2 CORE ALTERATION ..................................................                                                                                 1-2 CORE OPERATING LIMITS REPORT .......                                     ...............................                                           1-2 DOSE EQUIVALENT 1-131 ............................................                                                                                1-2 E-AVERAGE DISINTEGRATION ENERGY ..................................                                                                                 1-3 ENGINEERED SAFETY FEATURE RESPONSE TIME ...........................                                                                                1-3 FREQUENCY NOTATION ................................................                                                                                1-3 FULLY WITHDRAWN ...................................................                                                                                1-3 GASEOUS RADWASTE ,TREATMENT SYSTEM ................................                                                                                1-3 IDENTIFIED LEAKAGE ................................................                                                                                1-3 MEMBER(S) OF THE PUBLIC ..........................................                                                                                  1-4 OFFSITE DOSE CALCULATION MANUAL (ODC.)...........................                                                                                  1-4 0     OPERABLE - OPERABILITY ...........................................
OPERATIONAL MODE - MODE ...........................................
PHYSICS TESTS .....................................................
1-4 1-4 1-5 I
PRESSURE BOUNDARY LEAKAGE ........................................                                                                                 1-5 PROCESS CONTROL PROGRAM (PCP) ....................................                                                                                 1-5 PURGE-PURGING .....................................................                                                                                1-5 QUADRANT POWER TILT RATIO ........................................                                                                                 1-5 RATED THERMAL POWER ..............................................                                                                                 1-5 REACTOR TRIP SYSTEM RESPONSE TIME ................................                                                                                 1-6 REPORTABLE EVENT ..................................................                                                                                1-6 SHUTDOWN MARGIN ..................................................                                                                                 1-6 SITE BOUNDARY .....................................................                                                                                1-6 SOLIDIFICATION . ..................................................                                                                                1-6 SOURCE CHECK .....................................................                                                                                 1-6 STAGGERED TEST BASIS .............................................                                                                                 1-6 THERMAL POWER ..................................................                                                                               ... 1-7 UNIDENTIFIED LEAKAGE . .............................................                                                                               1-7 UNRESTRICTED AREA ................................................                                                                                 1-7 VENTILATION EXHAUST TREATMENT SYSTEM ..............................                                                                                1-7 VENTING ......           ..............               ......................................                                                        1-7 SALEM - UNIT 2                                                I                                                         Amendment No.                 206

SAflTY LnCTS AM L=ThCG SAFETY SYSTEM~ SZTT3XGS 2.1. SflTy L2921 Reactor Core . . . . . ........
                                          ...         . ...     . . .  .  .   .4  .
                                                                                  *.2-1 Reactor Coolant System Pressure     .....................                      .2-3 2.2- LZMTfl#G SAnflTT  STS?!N  !$ fI2 Reactor Trip System frustcetation Setpointa                    ......
                                                                         ....         2-4 BSUES 2.21 Sh-LfL291 AT' Reactor Cor* .. . . . . . . . . . . .. .. . . . . .. . . B 2-2.
Reactor Coois~nt System Preszuxe.............................. B 2-2 2.2 Lll,=M    SAY!T-Y-SYSTZ2( AITTZN-93 Reactor Trip System ZInstrumentation- SatPci~tg............. ;B 2-3 SAUX - WIT 2                             xx                                - ~ZT2 mendmetzz No.197

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION                                                                                      PAGE 3/4.0       APPLICABILITY .      . ..    . . . . . . . . . . . .                  . .. 3/4 0-1 I                     mi 3/4.1.      REACTIVITY CONTROL SYSTEMS 3/4.1.1     BORATION CONTROL Shutdown Margin - Tavg > 2000F . a . o       . * . .            .  .           3/4 1-1 Shutdown Margin      Tayg < 200F * . . .                                       3/4 1-3 Moderator Temperature Coefficient . . . . * . .....                            3/4 1-4 Minimum Temperature for Criticality . . . . . . .                              3/4 1-6 3/4.1.2     BORATION SYSTEMS Flow Paths -Shutdown        a .                *   .    . 0   0  S   *   . 3/4 1-7 Flow Paths - Operating . .              . ."   *   .     . a   *
* 0  3/4 1-8 Charging Pump - Shutdown . . . ....
* a    . a   6      .*  S   3/4 1-9 Charging Pump - Operating . . . . # a *         *  . 0   S  S
* a  3/4 1-10 Borated Water Sources - Shutdown           . . *   . a   .   .
* a   3/4 1-11 Borated Water Sources - Operating - . .
* 0     9   9  9
* S  3/4 1-12 3/4.1.3     MOVABLE CONTROL ASSEMBLIES Group Height    . . . .  . , .   . . .  .      0  9    ~   a   ~      a   a   3/4 1-13 Posi~tion Indicating Systems - Operating
* S    ~   5   4 a
5  4  3/4 1-16 Position Indicating Systems - Shutdown         *   . 9    S  a 9
6   4  3/4 1-17 Rod Drop Time . . . . . . . . . . . . .
* 9     S   ~  9       . I 3/4 1-18 Shutdown Rod Insertion Limit- ....
* 9    9   5   4 a    4   . 3/4 1-19.
Control Rod Insertion Limits .       *  .
* a    S   S  9       . S 3/4 1-20 SALEM - UNIT 2                            III                 SALEM-UNI 2 II No. 28 Aknendment

INDEX LIMITING CONDITIONS    FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTI( ON                                                                                                       PAGE 3/4 .2     POWER'DISTRIBUTION            LIMITS 3/4.2 .1   AXIAL FILUX DIFFERENCE                 .........................                    ........         3/4 2-1
        .2 HEAT FLUX HOT CHANNEL FACTOR ..................                                     ........         3/4  2-5 3/1,2 3/4.2 . 3  NUCLEAR ENTHALPY HOT CHTANNEL FACTOR ............                                                    3/4  2-9 3/4.2 .4   QUADRANT   POWER TILT RATIO .....................                                   ........         3/4  2-13 3/4.2      DNB PARAMETERS      ...................................                                      .. .... 3/4  2-1.6 3/4.3      IN ST RUMENTAT I ON 3/4:. 3, 1 REACTOR TRIP SYSynTEJPM 'LNS'l'RUMENTAj.'I'TON                                                    " A3/4 3-1          .
3 /4.3' 2. ENGINEERED ,SAFE,'TY FElR].EUJ,;ACTUAT.ON                          ,Y.TEM INSTRUMENTATION ............................                                ...........              3/4 3-14 3/4.3.3    MONITORING INSTRUMEaTATION Radiation Monitoring IristrumcntatJori                              .......         ........         3/4 3-38 ReImote S9hutdown Instrumerntation                               .                                        3-.43 Accident Monitoring Instrumentatrion                                               .......            3/4 3-50 Radioact:Lve LIiquid Effluent Monitc)ringcj ,'
Iftstrumentati .on.. . ....                       .............     .                              . 3/4  3-53        .
I Power Di~str'ilbuLion Moniltorinhg System .......                                                   .3/4  3-65        .
3/4.3.4    DELETED SALEM - UNIT12                                              TV                                        Amendment No.        265

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION                                                                                                                    PAGE 3/4.4      REACTOR COOLANT SYSTEM 3/4.4, 1   REACTOR COOLANT LOOPS AND COOLANT CIRCULATION Startup and Power Operation ...............................................................                    3/4 4-1 Hot Standby ..........................................................................................         3/4 4-2 Hot Shutdown .......................................................................................           3/4 44-3 Cold Shutdown ...................................................................................            3/4 4-4a 3/4.4, 2   SAFETY VALVES - SHUTDOW N.........................................................                             3/4 4-5 3/4.4, 3   SAFETY VALVES - O PERATING .........................................................                           3/4 4-6 3/4,4 .4  PRESSURIZER ....................................................................................               3/44-7 314.4 .5  RELIEF VALVES ..............................                .........   .................................... 3/44-8 314.4 .6  STEAM GENERATOR (SG) TUBE INTEGRITY ...................................                                        3/4 4-9 314.4 .7  REACTOR COOLANT SYSTEM LEAKAGE Leakage Detection System ................................................................                     3/4 4-16 Operational Leakage .....................................................................               :.... 3/4 4-17 3/4,4 .8  DELETED 314.4 3/4.4 .9  SPECIFIC ACTIVITY ..........................................................................                  3/4 4-23 3/4.4 .10 PRESSURE/TEMPERATURE LIMITS Reactor Coolant System .....................................................................                  3/4 4-27 Pressurizer .........................................................................................         3/4 4-30 Overpressure Protection Systems ......................................................                        3/4 4-31 314.4 .11 DELETED ...........................................................................................           3/44-33 3/4.4 .12 HEAD VENTS ..................................................................................                 3/4 4-34 SALEM - UNIT 2                                                   V                                               Amendment No. 281

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTIC)N                                                                                                  PAGE 3/4.5         EMERGENCY CORE'COOLING SYSTEMS                            (ECCS) 3/4. 5 .1     ACCUMULATORS . ...................................                                  ..... 3/4 5-1 3/4. 5 .2     ECCS SUBSYSTEMS    -    Tavg &#x17d; 350OF ..........................                              3/4 5-3 3/4.5 .3      ECCS SUBSYSTEMS    -    Tavg < 350DF .. .........................                            3/4 5-7 3/4.5. .4     SEAL INJECTION FLOW ..................................                                      3/4 5-8a 3/4.5 .5      REFUELING WATER STORAGE TANK                        .........................               3/4 5-9 3/4.6         CONTAINMENT SYSTEMS 3/4.6.1      *PRIMARY CONTAINMENT Containment Integrity. ....                                       ...............         .3/4   6-1 Containment Leakage .................................                                     .3/4   6-2 Containment Air Locks ..................................                                  .3/4   6-4
           !'Internal   Pressure ..................................                                      .3/4   6-6 Air Temperature .....................................                                     .3/4   6-7 Containment Structural Integrity ......................                                   .3/4   6-,8B..
Containment Ventilation System .......................                                    .3/4   6-9 DEPRESSURIZATION AND COOLING SYSTEMS 3/4.6.2 Containment Spray System                           ............... .......... .3/4               6-10
           .. Spray Additive System .................................                                    .3/4   6-11 Containment Cooling System                         ........................... .3/4              6-12 3/4.6.3        CONTAINMENT ISOLATION VALVES                        ........................              .3/4   6-14 SALEM - UNIT 2                          VI                                                       Amendment No.       264

INDEX LIMITING  CONDITIONS FOR OPERATION AND SURVEILLANCE                                                     REQUIREMENTS SECTION                                                                                                              PAGE 3/4.7      PLANT SYSTEMS 3/4.7.1    TURBINE CYCLE Safety Valves .........................................                                                   3/4  7-1 Auxiliary Feedwater System ............................                                                   3/4  7-5 Auxiliary Feed Storage Tank ...........................                                                   3/4  7-7 Activity . ..............................................                                                 3/4  7-8 Main Steam Line Isolation Valves ......................                                                   3/4  7-10 3/4.7.2    STEAM GENERATOR PRESSURE/TEMPERATURE LIMITATION .............................................                                                  3/4 7-11 3/4.-7.3  COMPONENT COOLING WATER SYSTEM ........................                                                   3/4 7-12 3/4.7.4    SERVICE WATER SYSTEM                     ..................................                               3/4 7-13 3/4.7.5   FLOOD PROTECTION              ......................................                                      3/4 7-14 3/4.7.6   CONTROL ROOM EMERGENCY AIR CONDITIONING SYSTEM ...................................                                                   3/4 7-15 3/4.7.7   AUXILIARY BUILDING VENTILATION SYSTEM                                                    ................ 3/4 7-1B 3/4.7.8   SEALED SOURCE CONTAMINATION                                  ...........................                  3/4 7-21 3/4.7.9   SNUBBERS  ....     .. .     .......................................                                       3/4 7--23 3/4.7.10  CHILLED WATER SYSTEM -
AUXILIARY BUILDING SUBSYSTEM ...........................                                                  3/4 7-28 3/4.7.11  FUEL STORAGE:POOL BORON CONCENTRATION ..................                                                  3/4 7-30 3/4.7.12  FUEL ASSEMBLY STORAGE IN THE SPENT FUEL POOL ...........                                                  3/4 7-31 SALEM - UNIT 2                                                      VII                                             Amendment No.252

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION                                                                                                      PAGE 3/4.8     ELECTRICAL POWER SYSTEMS 3/4.8.1   A. C.,SOURCES Operating ..............................................                                           3/4 8-1 Shutdown ..............................................                                            3/4 8-7a 3/4.8.2   ONSITE POWER DISTRIBUTION SYSTEMS A.C. Distribution - Operating ..........................                                           3/4  8-8 A.C. Distribution - Shutdown .......                                ...................            3/4  8-9 125-Volt D.C. Distribution - Operating ................                                            3/4  8-10 125-Volt D.C. Distribution - Shutdown .................                                            3/4  8-12 28-Volt D.C. Distribution - Operating .................                                            3/4  8-13 28-Volt D.C. Distribution - Shutdown ..................                                            3/4  8-15 3/4.8.3   ELECTRICAL EQUIPMENT PROTECTIVE DEVICES Containment Penetration Conductor Overcurrent Protective Devices .............                         .......................                   3/4 8-16 SALEM - UNIT 2                                Vill                                                Amendment No. 206

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION                                                                                                                  PAGE 3/4.9       REFUELING OPERATIONS 3/4.9.1     BORON CONCENTRATION                    ...................................                                   3/4   9-1 3/4.9.2     INSTRUMENTATION              .......................................                                         3/4 9-2 3/4.9.3     DECAY TIME      ............................................                                                 3/4 9-3 3/4.9.4     CONTAINMENT BUILDING PENETRATIONS                                            .....................           3/4 9-4 3/4.9.5     DELETED ...............................................                                                       3/4 9-5 3/4.9.6    DELETED ...............................................                                                       3/4 9-6 3/4.9.7    DELETED  ...............................................                                                      3/4 9-7 3/4.9.8    RESIDUAL HEAT REMOVAL AND COOLANT CIRCULATION All Water Levels ......................................                                                       3/4  9-8 Low Water Level .......................................                                                      3/4  9-9 3/4.9.9    DELETED 3/4.9.1 .0  WATER LEVEL - REACTOR VESSEL                                    ..........................                   3/4  9-11 3/4.9.1 1   STORAGE POOL WATER LEVEL ..............................                                                      3/4  9-12 3/4.9.1 .2 FUEL HANDLING AREA VENTILATION SYSTEM ..................                                                      3/4   9-13 3/4.10      SPECIAL TEST EXCEPTIONS 3/4.10. .1  SHUTDOWN MARGIN .......................................                                                      3/4 10-1 3/4.10 .2   GROUP HEIGHT, INSERTION AND POWER DISTRIBUTION LIMITS ...................................                                                       3/4 10-2 3/4.10 .3  PHYSICS TESTS            .........................................                                            3/4 10-4 3/4.10 .4  NO FLOW TESTS            .........................................                                            3/4 10-5 SALEM - UNIT 2                                      IX                                                       Amendment No.277

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION                                                                                              PAGE 3/4.11     RADIOACTIVE EFFLUENTS 3/4.11.1   LIQUID EFFLUENTS Liquid Holdup Tanks .....................................                                 3/4 11-7 3/4.11.2. GASEOUS EFFLUENTS Explosive Gas Mixture                      ...................................            3/4 11-15 3/4.11.3   Deleted ................................................                                  3/4 11-17 3/4.11.4   Deleted . ............                   ......           ........................... 3/4 11-18 3/4.12     Deleted SALEM - UNIT 2                                                        X                         Amendment No. 215

INDEX BASES SECTION                                                                         PAGE 3/4.0      APPLICABILITY .........................................              B 3/4 0-1 3/4.1      REACTIVITY CONTROL SYSTEMS 3/4.1.1    BORATION CONTROL ......................................              B 3/4 1-1 3/4.1.2    BORATION SYSTEMS ......................................              B 3/4 1-3 3/4.1.3    MOVABLE CONTROL ASSEMBLIES ............................              B 3/4 1-4 3/4.2      POWER DISTRIBUTION LIMITS 3/4.2.1   AXIAL FLUX DIFFERENCE .................................              B 3/4 2-1 3/4.2.2   HEAT FLUX AND NUCLEAR ENTHALPY and 3/4.2.3   HOT CHANNEL AND RADIAL PEAKZ'NG FACTOR ........          ........... B 3/4 2-4 3/4.2.4    QUADRANT POWER TILT RATIO .............................             9 3/4 2-5 3/4.2.5    DNB PARAMETERS ........................................             B 3/4 2-6 SALEM - UNIT 2                                            Xx                   Amendment No. 206

INDEX BASES SECTION                                                                                                                    PAGE 3/4.3      .INSTRUMENTATION 3/4':3.1I PROTECTIVE AND         AND 3/4.3.2     ENGINEERED SAFETY FEATURES (ESF)
INSTR UM ENTATIO N................................................... .................                     B 3/4 3-1 3W4:3.3    'MONITORING INSTRUMENTATION ..................                                                             B 3/4 3:1a 3/4.4       REACTOR COOLANT SYSTEM 3/4.4.1     REACTOR COOLANT LOOPS AND COOLANT CIRCULATION .....................................                                                           B 314 4-1 3/4.4.2 anrd      SAFETY VALVES ....                    ........................................         ........... .. ... B 3/4 4-2 3/4.4.3                                                                                              :
314.4.4,   , PRESSURIZER .........                             .........     ...........                                B 3/44-2 314A4.5 , ..RELIEF VALVES .................................                                                                     -2 sA 3/4.4.6,!- ,.-STEAM GENERATOR (SG) TUBE INTEGRITY ........                                                              B 344-3 3/4.4.7      REACTOR COOLANT SYSTEM LEAKAGE ......................................                                      B 3/4 4-4 3/4.4.8     DELETED 3/4.4.9     SPEC IFIC ACTIV ITY ........................................................................               B 3/4 4-6 3/4.4,10    PRESSURE/TEMPERATURE LIMITS ...............................................                                B 3/4 4-7 3/4.4.11    D E LET E D ........................................................................................      B 3/4 4-18 3/4.4.12    REACTOR VESSEL HEAD VENTS .................................................                               B 3/4 4-18 SALEM - UNIT 2                                                      Xll                                             Amendment No. 281

INDEX BASES SECTION                                                                                                          PAGE 3/4.5      EMERGENCY CORE COOLING SYSTEMS                                 (ECCS) 3/4.5.1    ACCUMULATORS   ..........................................                                             B 3/4  5-1 3/4.5.2 and     ECCS SUBSYSTEMS        .......................................                                        B 3/4 5-1 3/4 .5.3 3/4.5.4    SEAL INJECTION FLOW              ...................................                                 B 3/4 5-2 3/4.5.5    REFUELING WATER STORAGE TANK                             (RWST) ....................                 B 3/4 5-3 3/4.6      CONTAINMENT SYSTEMS 3/4.6.1    PRIMARY CONTAINMENT              ...................................                                 B 3/4  6-1 3/4.6.2    DEPRESSURIZATION AND COOLING SYSTEMS                                           .................. B 3/4 6-3 3/4.6.3    CONTAINMENT ISOLATION VALVES                              ..........................                B   3/4  6-4 SALEM - UNIT 2                                                 XIII                                         Amendment No. 264

INDEX BASES SECTION                                                                                                                                                                             PAGE 3/4.7         PLANT SYSTEMS 3 /4 .7. 1    T URB INE CY CLE ...........................................................................................................................                          B 3 /4          7- 1 3/4.7.1       STEAM GENERATOR PRESSURE/TEMPERATURE L I MI TA T I ON ..........................................................................................................................................           B 3 / 4 7- 4 3/4.7.3      COMPONENT COOLING WATER SYSTEM .............................................................................                                                          B.3/4 7-4 3/4. 7 .4    SERV ICE WA TER SYSTEM ............................................................................................................                                   B 3 /4          7- 4 3 /4 .7 .5   FL OOD PRO T E C T IO N ........................................................................................................                                      B...............
B -3/4 7- 5 3/4.7.6      CONTROL ROOM EMERGENCY AIR CONDITIONING SYSTEM .......................................................................B 3/4                                                                                       7-5 3/4.7.7      AUXILIRY BUILDING EXHAUST AIR FILTRATION SYSTEM ...................                                                                   ........                 .               ................... B 3./4           7-5c 3/4.7 .8     SEALED SOURCE CONTAMINATION ....................................................................................                                                      B 3/4 7-5c 3 / 4 .7 . 9 S NUBBE R S ...............................................................................................................................................           B 3 / 4 7- 6 3/4.7.10     CHILLED WATER SYSTEM A UX ILIA RY BUILDING SYSTEM .............................................................................................                                            B 3 /4           7-8 3/4.7.11     FUEL STORAGE POOL BORON CONCENTRATION                                                                        ........................................................ B 3/4 7-9 3/4.7.12      FUEL ASSEMBLY STORAGE IN THE SPENT FUEL POOL .................................                                                                                        B 3/4 7-12 3/4.8         ELECTRICAL POWER SYSTEMS 3 / 4 .8 .1  A . C . S OUR CE S .................................................................................................................................                   B 3/ 4 8- 1 3/4.8.2       ONSITE POWER DISTRIBUTION SYSTEMS .....................................................................                                                               B 3/48-1 3/4.8.3       ELECTRICAL EQUIPMENT                                PROTECTIVE DEVICES .....................                                                                          B 3/4           8-4 SALEM - UNIT 2                                                              XIV                                                                              Amendment No.                       244

INDEX BASES SECTIOb                                                                                           PAGE 3/4.9        REFUELING OPERATIONS BASES 3/4.9.1      BORON CONCENTRATION ........                            .............                3/4  9-1 3/4.9.2      INSTRUMENTATION ..........                         ...............                   3/4  9-lb 3/4.9.3      DECAY TIME   . .  .    . .        .    .     .     .    .     .    .  . .    . . . 3/4  9-lb 3/4.9.       CONTAINMENT BUILDING PENETRATIONS ..........                                         3/4  9-ic 3/4.9.
5    COMMUNICATIONS    ...............                                                    3/4  9-3 3/4.9.
6    MANIPULATOR CRANE ...             ...........                           .......      3/4  9-3 3/4.9. 7     CRANE TRAVEL - SPENT FUEL STORAGE BUILDING                                           3/4  9-3 3/4.9. 8     RESIDUAL HEAT REMOVAL AND COOLANT CIRCULATION                                        3/4  9-3 3/4.9. 9    CONTAINMENT PURGE AND PRESSURE-VACUUM RELIEF ISOLATION SYSTEM          . .............                                          B 3/4 9-4 3/4.9. 10    WATER LEVEL - REACTOR VESSEL and        AND 3/4.9.: 311  STORAGE POOL   . . . . . . . .                           .    .    . .  .    . . . B 3/4 9-4 3/4.9.: 12   FUEL HANDLING AREA VENTILATION SYSTEM                                   ....       B 3/4 9-4 3/4.10       SPECIAL TEST EXCEPTIONS 3/4.10 .1    SHUTDOWN MARGIN ........                      ............                         B 3/4 10-1 3/4.10 .2    GROUP HEIGHT, INSERTION AND POWER DISTRIBUTION LIMITS ....                      ..........                           B 3/4 10-1 3/4.10 .3    PHYSICS TESTS ........                  .............                              B 3/4 10-1 3/4.10 .4   NO FLOW TESTS ........                  .............                              B 3/4 10-1 SALEM - UNIT 2                                       XV                                         Amendment No. 244

INDEX BASES SECTION                                                                                                        PAGE 3/4.11    RADIOACTIVE EFFLUENTS 3/4.11.1  LIQUID EFFLUENTS                ................................                                   .B   3/4 11-1 3/4.11.2  GASEOUS EFFLUENTS . .................................                                               .B 3/4 11-3 3/4.11.3  De let ed   . ...     .........            .. .. .......         .. ...  ....  ....   . ...  ...      B 3/4 11-6 3/4.11.4  De le ed  . . ..........             ...     . .. . .. .. ...      . ... . ... ...  .. .. ...         B 3/4  11-7 3/4.12    Deleted SALEM - UNIT 2                                                        XVI                                  Amendment No. 215

INDEX DESIGN FEATURES SECTION                                                                                                    PAGE 5.1 SITE Exclusion Area .................................................                                       5-1 Low Population Zone .......................                                                            5-1 Unrestricted Areas for Radioactive Gaseous andLiquid Effluents ......................................................                                       5-1 5.2  CONTAINMENT Configuration ................                           ..................................            5-1 Design Pressure and Temperature ................................                                       5-4 5.3  REACTOR CORE Fuel Assemblies .................................................                                      5-4 Control Rod Assemblies .........................................                                       5-4 5.4  REACTOR COOLANT SYSTEM Design Pressure and Temperature ................................                                       5-4 5.5  METEOROLOGICAL TOWER LOCATION ..................................                                       5-5 5.6  FUEL STORAGE criticality ....................................................                                       5-5 Drainage .......................................................                                       5-5b capacity .......................................................                                       5-5b 5.7  COMPONENT CYCLIC OR TRANSIENT LIMIT .............................                                      5-5b SALEM - UNIT 2                                                     XVII                          . Amendment No. 2M

INDEX ADMINISTRATIVE         CONTROLS SECTION                                                                                                                                                                                                  PAGE
: 6. 1      R E S PO NS I B IL I T Y .........................................................................................................................................                                 6- 1 6.2       ORGANIZATION Onsite and Office Organizations ..................................................................................                                                                                    6-1 Facility Staff ...................................................................................................                                             - ................                    6.1 Sh i ft Techn ica l Adv isor .....................................................................................................................                                                   6-7 6.3       FACILITY STAFFQUALIFICATIONS                                                        ...........................                                            .............                            6-7 6 .4      T RA I NI NG .................................................................................................................               .................... ;..................... *.*&deg;.... 6- 7
* 6.5       REVIEW AND AUDIT                             (THISGSECTION                                 DELETED) ..................                            .......
                                                                                                                                                                .............            ............,6-8 6 .6      RE PORTABLE EVENT ACTION .....................................................................................................................                                                        6-16 6.7       SAFETY LIMIT VIOLATION ............                                                               ...............................................................                                     6-16 6 .8      PROCE DURES A ND PROGRAM S ....................................................................................................................                                                       6-17 6.9      REPORTING REQUIREMENTS 6 .9 .1       RO UT IN E R E PO R T S                      ....................................................................................................................................                  6- 2 0 6 .9 .2       S PEC IA L RE PORTS . ......................................................................................................................                                          ............ 6 -2 4b 6.10     RECORD RETENTION ...................................................                                                                                          .........               ........         6-25 6.11      RADIATION PROTECTION PROGRAM ....... I                                                                                  ..........................                           ........ ......              26 6.12      H IGH. RAD IATION A REA ...................................................                                     ........................................................................               6-2 7 6.13      PROCESS CONTROL PROGRAM (PCP)                                                        ........................................................................................                    ... 6-28 6.14      OFFSITE DOSE CALCULATION MANUAL                                                               (ODCM)                ........................................................................           6-29 6.15      MAJOR CHANGES TO RADIOACTIVE LIQUID, GASEOUS AND SOLID WASTE TREATMENT SYSTEMS .......................                                                                                   ............................................... 6-29 6.16     TECHNICAL SPECIFICATION                                           (TS)            BASES CONTROL PROGRAM ....................................                                                           6-30 6.17     CONTROL ROOM ENVELOPE HABITABILITY PROGRAM ...........................................................                                                                                                 6-31 SALEM -    UNIT 2                                                                           XVIII                                                                      Amendment No.                                269 I

APPENDIX B TO FACILITY OPERATING LICENSE NO. DPR-70 SALEM GENERATING STATION UNIT 1 DOCKET NO. 50-272 AND FACILITY OPERATING LICENSE NO. DPR-75 SALEM GENERATING STATION UNIT 2 DOCKET NO. 50-311 PSEG NUCLEAR LLC I
ENVIRONMENTAL  PROTECTION PLAN (NONRADIOLOGICAL)
Amendment No. - M214 I

SAL4 GDERATIG S=TICN UNIT *I.                   1 AND 2 ENVII401MENTL PROTECTION PLAN (NCNRDIOIDGICAL)
TABLE OF CONIE' Section 1.0  Objectives of the Envirmmental Protection Plan .............                                1-1 2.0  Envirormental, Protection Issues .............................                              2-1 3.0  CorSistenxy Requiremnts ....................................                                3-1 3.1  Plant Design and Operation ..................................                               3-1 3.2  Reporting Related to the NIR)ES Permit and State Certification .............................................                              3-2 3.3  Cwqes RquIred for cOmpliaie with Other Erviramwrtal Reulations ............................................                                  3-3 4 .0 Envirm~nrta1 Ccndi.ti                       ..................................              4-1 4.1  Unusual or Important Environmntal Events ...................                                4-1 4.2  EnvironEental Monitorin ................................                                    4-1
: 5. 0 Administrative Procedures                           ...............................         5-1 5.1  Review .......................                             .............................. 5-1 5.2  Records Retention ...........................................                               5-1 5.3  Changes in Envircrmwta.                       Protection Plan ....................          5-2 5.4  Plant      orting Requirements............................ 55-2 Amendment No. 77

1.0    objectives of the Enivirarental Protection Plan The Evironmntal Protection Plan (EPP) is to provide for protection of nonradiological enviirormntal values during operation of the nuclear facility. The principal objectives of the EPP are as follows:
(1)  Verify that the facility is operated in an environmentally acceptable manner, as establishei by the Final Eviron-ental Statement -O operating Licensing Stage (FES-OL) and other NFC environmental impact assessnts.
(2)  Coordinate NFC requirments and maintain omnsistency with other Federal, State and local requirmeunts for environmntal protection.
(3)  Keep NRC informed of the ernvirormental effects of facility construction and operation and of actions taken to control those effects.
Envi=mntal concerns identified in the FES-OL which relate to water quality matters are regulated by way of the licensee's 1VE     permit.
1.-1 Amendment No. 77

2.0     E&nv'iror       Protection Issues In the FES, dated April 1973, the staff considered the environmental impacts associated with the operation of Salem Generating Station Unit Nos. 1 and 2. Certain environmental issues were identified which reqired stiy      or licerse ounditions to resolve and to assure adequate protection of the environment. The Appendix B Environmenta  Technical Specifications (EMS) issued with the operating license included discharge restrictions and monitoring programs related to aquatic and terrestrial resources.
: 1. Protection of the aquatic environment by limiting the thermal characteristics of the discharge.
: 2. Protection of the aquatic envirorment fx      biocide used in plant operations.
: 3. Protection of the aquatic environment from suspee       solids and changes in pH in releases from the non-radioactive liquid waste disposal vystm.
: 4. Surveillan      programs for dissolved gases, sspended solids, chemical releases, and the general aquatic ecological surveys to establish iupact of plant operation on the biotic environment.
2-i Amendment No. 77

Z.*1.a       L;3-m-a Requirements for study of station intake and discharges effects were remived from the ETS by License Axen.mints 51 (Unit 1) and 18 Unit 2, dated March 14, 1983 and March ii,  1983, respectively. These issues now are adressed by the effluent limitations and nmniLtorirg req~irenents contained in the effective NUPVE5 Permit No. NZ0005622 issued by the State of New Jersey, and by the determination of the State of New Jersey on the Section 316(a) and (b) destration subnitted by licensee. The NRc will rely on the State for regulation of matters involving water quality and aquatic biota.
2.2    Terrestrial Issues Reuirents for study of station effects on terrapins and raptors have been met.
2-2 Amendment No. 77

3.1     Plant Design and Operation The licensee may make changes in station design or operation or perform tests or experiments affecting the enrvix=ort provided such activities do not involve an unreviewed environrmxtal question and do not involve a change in the EPP*. Changes in station design or operation perfornwae of tests or experiments which do not affect the envirormient are not subject to the reuirents of this EPP.
Activities governed by Section 3.3 are not subject to the requirements of this Section.
Before engaging in additional cstriuction or operational activities which may significantly affect the envizoment, the licersee shall prepare and record an enviro    ntal evaluation of such activity.
Activities are excluded fr-m this reuirent     if all measurable nonradiological environmental effects are confined to the on-site areas previously disturbed during site preparation and plan4 crstruction.
When the evaluation indicates that such activity involves an unreviewed envirormental question, the licensee shall provide a written evaluation of such activity and obtain prior NRC approval.
When such activity involves a change in the EPP, such activity and change to the EPP may be implemented only in accordance with an appropriate license ametbient as set forth in Section 5.3 of this EPP.
* This provision does not relieve the licensee of the reuireents of 10 CFR 50.59.
3-1 Amendment No. 77

t  pvo&#xfd;,    ciin5, . L   OL      rniettiF SfldT sud . eu uzav    io    ou ve an unreviewed envirormntal question if it concerns:            (1) a matter which may result in a significant increase in any adverse envirarmental iupact previously evaluated in the FES-OL, environmentavl         impact appraisals, or in any decisions of the Atomic Safety and Licensing Board; or (2) as significant change in effluents or power level; or (3) a matter, not previously reviewed and evaluated in the documents specified   in (1) of this Subsection, which may have a significant avse     environmental impact.
The licensee shall maintain records of changes in facility design or operation and of tests and experiments carried out pursuant to this Subsection. These records shall include written evaluations which provide bases for the determination that the change, test, or experiment does not involve an unreviewed environmental question or constitute a decrease in the effectiveness of this EPP to meet the cojectives specified in Section 1.0. The licensee shall include as part of the Annual Environmental operating Report (per Subsectior45.4 .1) brief descriptions, analyses, interpretatio,          and evaluations of such chanes, tests and epriments.
3.2    Reporting Related to the NUPDE      Permit or the State Certification Caarges to, or reneals of, the N             Permit or the State certification shall be reported to the NRC within 30 days following the
.date the change or renewal is approved.         If a permit or certification, in part or in its eitirety, is appealed and staye,           the NRC shall be notified within 30 days following the date the stay is granted.
3-2                                      Amendment No. 77

The licensee shall notify the HRC of dcnges to the effective bUnMS Permit proposed by the licensee by providit NEC with a coy of the proposed chage at the same time it is subitted to the permitting agency. The licensee shall provide the NRC a copy of the application for renewal of the NXMES Permit at the same time the application is submitted to the permitting agenc~y.
3.3     Charnes Required for Cumliance with Other Environmental Regulations Changes in plant design or operaticn and performance of tests or experiments which are required to achieve oocplian* with other Federal, State, and local enviromexntal regulations are not subject to the reqirements of Section 3.1.
3-3 Amendment No. 77

4.0     Environmental Conditions 4.1     Unusual or Important Environmental Events Any occurrence of an unusual or important event that indicates or could result in significant environmental impact causally related to plant operation shall be recorded and reported to the NRC within 24 hours followed by a written report per Subsection 5.4.2. The following are examples: excessive bird impaction events; onsite plant or animal disease outbreaks; mortality or unusual occurrence of any species protected by the Endangered Species Act of 1973; fish kills or impingement events on the intake screens; increase in nuisance organisms or conditions; unanticipated or emergency discharge of waste water or chemical substances.
No routine monitoring programs are required to implement this condition.
4.2    Environmental Monitoring 4.2.1 Aquatic Monitoring The certifications and permits required under the Clean Water Act provide mechanisms for protecting water quality and, indirectly, aquatic biota. The Nuclear Regulatory Commission (NRC) will rely on the decisions made by the State of New Jersey under the authority of the Clean Water Act and, in the case of sea turtles and shortnose sturgeon, decisions made by the National Marine Fisheries Service (NMFS) under the authority of the Endangered Species Act, for any requirements pertaining to aquatic monitoring.
In accordance with Section 7(a) of the Endangered Species Act, on May 14, 1993, the National Marine Fisheries Service issued a Section 7 Consultation Biological Opinion related to the operation of Salem Unit 1 and 2 Generating Stations. This Section 7 Consultation entitled, "Reinitiation of a consultation in accordance with Section 7(a) of the Endangered Species Act regarding continued operation of the Salem and Hope Creek Nuclear Generating Stations on the eastern shore of the Delaware River in New Jersey," concluded that "...continued operation is not likely to jeopardize the continued existence of listed species."
PSEG Nuclear LLC shall adhere to the specific requirements within the Incidental Take Statement, to the Biological Opinion. Changes to the incidental take statement must be proceeded by consultation between the NRC, as the authorizing agency, and NMFS.
The Conservation Recommendations, to the Biological Opinion suggests conservation recommendations for implementation by Salem Generating Station.
The Station shall implement these recommendations to the satisfaction of the NRC and National Marine Fisheries Service.
SALEM UNIT 2                          4-1               Amendment No. 1- 214

4.2.2     Terrestrial Monitoring Terrestrial monitoring is  not required.
SALEM UNIT 2                           4-2      Amendment No. 196

5.1     Review The licensee shall provide for review of ccipliance with the EPP.      The review shall be corkucted in*erhdently of the individual or groups responsible for performing the specific activity. A description of the organization structure utilized to achieve the independent review function and results of the review activities shall be maintained and made available for inspection.
5.2     Rrds     Retention Records and logs relative to the environmntal aspects of station operation shall be made and retaine     in a manner oivenient for review and inspection. These records and logs shall be made available to NRC on request.
Records of modifications to station strucres, systaMs and cCoPcnents determirm    to potentially affect the citnuid protsction of the envirormental shall be retained for the life of the station. All other reords, data and logs relating to this EPP shall be retained for five years or, where applicable, in acrdanc       with the reuremnts of other agercies.
5-1 Amendment No. 77

Requests for changes in the EPP shall include an assessment of the envirormntal. impact of the proposed cane and a suporting justification. Implementatico of such chwaves in the EPP shall not ommence prior to NEC approval of the proposed ciarqes in the form of a license amendment incorporating the appropriate revision to the EPP.
5.4     Plant R*Ortirg Peuirements 5.4.1   Rmitine Reports An Annual Ervirurntal Operatirn    Report describing implementation of this EPP for the previous year shall be submitted to the NRC prior to May 1 of each year.
Me report shall include %=miries and analyses of the results of the environmental protecion activities required by Subsection 4.2 (if any) of this EPP for the report period, including a comparison with related preerational studies, operational coitmls (as apropriate),
and previous rixiraiological envirozntal monitoring reports, and an asses,      of the observed impacts of the plant coeration on the envirYmnt. If harmful effects or evidence of trends toward irreversible damage to the evirormwnt are observed, the licensee shall provide a detailed analysis of the data and a proposed course of mitigating action.
5-2 Amendment No. 77

(1)   A list   of EPP noncompliances and the corrective actions taken to remedy them.
(2)   A list   of all changes in station design or operation,     tests, and experiments made in accordance with Subsection 3.1 which invclved a potentially significant unreviewed environmental question.
(3)   A list   of nonroutine reports submitted in accordance with Subsection 5.4.2.
In   the event that some results are not available by the report due date,   the report shall be submitted noting and explaining the missing results.      The missing results shall be submitted as soon as possible in a supplementary report.
5.4.2           Nonroutine Reports A written report shall be submitted to the NRC within 30 days of occurrence of a nonroutine event.       The report shall:     (a) describe, analyze,     and evaluate the event,  including extent and magnitude of the impact,     and plant operating characteristics;   (b)   describe the probable cause of the event;      (c) indicate the action taken to correct the reported event;      (d) indicate the corrective action taken to 5-3 Amendment No. 77

involving similar components or systems; and (e)  indicate the agencieE notified and their preliminary responses.
Events reportable under this subsection which also require reports to other Federal,  State or local agencies shall be reported in accordancE with those reporting requirements in lieu of the requirements of this subsection. The NRC shall be provided with a copy of such report at the same time it  is submitted to the other agency.
5-4 Amendment No. 77

APPENDIX C ADDITIONAL CONDITIONS OPERATING LICENSE NO. DPR-75 PSEG Nuclear LLC, and the Exelon Generation Company LLC shall following conditions on the schedules noted below:
comply with the I
Amendment    Additional Condition                                           Implementation Date Number The amendment shall be 175          The licensee is  authorized to relocate certain Technical      implemented within 60 Specification requirements to licensee-controlled documents. days from March 21, Implementation of this amendment shall include the            1997.
relocation of these technical specification requirements to the appropriate documents, as described in the licensee's application dated January 11, 1996, as supplemented by letters dated February 26, May 22, June 27, July 12, December 23, 1996 and March 17, 1997, and evaluated in the staff's safety evaluation attached to this amendment.
The amendment shall be 177          The licensee is  authorized to upgrade the initiation          implemented prior to circuitry for the power operated relief valves, as described   entry into Mode 3 from in the licensee's application dated January 31, 1997, as       the current outage for supplemented by letters dated March 14, April 8, and April     Salem, Unit 2.
28, 1997, and evaluated in the staff's safety evaluation attached to this amendment.
The amendment shall be 179          All modifications made in support of the amendment request     implemented prior to concerning Containment Fan Cooler Units (CFCU) response time   entry into Mode 3 from dated October 25, 1996, as described in the letters            the current outage for supplementing the amendment request dated December 11, 1996,   Salem,  Unit 2.
January 28, March 27, April 24, June 3, and June 12, 1997, shall be in conformance with the existing design basis for Salem Unit 2, and programmatic controls for tank monitoring instrumentation shall be as described in the letter dated April 24, 1997. Post modification testing and confirmatory analyses shall be as described in the letter dated March 27, 1997. Future changes to the design described in these submittals may be made in accordance with the provisions of 10 CFR 50.59. Further, the administrative controls associated with CFCU operability and containment integrity described in the letters dated March 27 and April 24, 1997, shall not be relaxed or changed without prior staff review until such time as the license has been amended to include the administrative controls as technical specification requirements.                                                  The amendment shall be 181                                                                         implemented within 30 The licensee shall perform an evaluation of the containment    days from July 17, liner anchorage by November 30, 1997, for the loading          1997.
induced on the containment liner during a Main Steam Line Break event to confirm the assumptions provided in   the Preliminary Safety Analysis Report and Updated Final Safety Analysis Report.
1                             Amendment No. 227

1.0 DEFINITIONS DEFINED TERMS 1.1 The DEFINED TERMS of this section appear in capitalized type and are applicable throughout these Technical Specifications.
ACTION 1.2 ACTION shall be that part of a specification which prescribes remedial measures required under designated conditions.
AXIAL FLUX DIFFERENCE 1.3 AXIAL FLUX DIFFERENCE shall be the difference in normalized flux signals between the top and bottom halves of a two section excore neutron detector.
CHANNEL CALIBRATION 1.4 A CHANNEL CALIBRATION shall be the adjustment, as necessary, of the channel output such that it responds with the necessary range and accuracy to known values of the parameter that the channel monitors. The CHANNEL CALIBRATION shall encompass the entire channel, including the required sensor, alarm, display, and trip functions, and shall include the CHANNEL FUNCTIONAL TEST. Calibration of instrument channels with resistance temperature detector (RTD) or thermocouple sensors may consist of an inplace qualitative assessment of sensor behavior and normal calibration of the remaining adjustable devices in the channel. Whenever an RTD or thermocouple sensing element is replaced, the next required CHANNEL CALIBRATION shall include an inplace cross calibration that compares the other sensing elements with the recently installed sensing element. The CHANNEL CALIBRATION may be performed by means of any series of sequential, overlapping, or total channel steps so that the entire channel is calibrated.
CHANNEL CHECK 1.5  A CHANNEL CHECK shall be the qualitative assessment of channel behavior during operation by observation. This determination shall include,  where possible, comparison of the channel indication and/or status with other indications and/or status derived from independent instrument channels measuring the same parameter.
CHANNEL FUNCTIONAL TEST 1.6 A CHANXEL FUNCTIONAL TEST shall be the injection of a simulated signal into the channel as close to the primary sensor as practicable to verify OPERABILITY including alarm and/or trip functions.
SALEM - UNIT 2                       1-1                     Amendment No. 174

DEFINITIONS CONTAINMENT INTEGRITY 1.7  CONTAINMENT INTEGRITY shall exist when:
1.7.1  All penetrations   required to be closed during accident conditions are either:
: a. Capable of being closed by an OPERABLE containment automatic isolation valve system, or
: b. Closed by manual valves, blind flanges, or deactivated automatic valves secured in their closed positions, except for valves that are opened under administrative control as permitted by Specification 3.6.3.
1.7.2  All equipment hatches are closed and sealed, 1.7.3  Each air lock is   OPERABLE pursuant to Specification 3.6.1.3, 1.7.4  The containment leakage rates are within the limits of Specification 3.6.1.2, and 1.7.5- The-sealing mechanism associated with each penetration   (e.g.,
welds, bellows:or 0-rings) is OPERABLE.
CORE ALTERATION-    .                                         .
1.8.1 CORE ALTERATION shall be the-movement of any fuel, sources,=or reactivity:control cqomponents, within the reactor vessel with the vessel- head removed and fuel in the vessel. Suspension of&#xfd;"CORE       -,
ALTERATIONS shall not preclude completion of movement, of a component-to..
a safe conservative position CORE OPERATING LIMITS REPORT 1.9    The CORE OPERATING LIMITS REPORT (COLR) is the unit-specific document that provides core operating limits for the current opeiating reload cycle. These cycle-specific core operating limits shall be determihed foreach reloaddCytle in accordance with Specification 6.9.19.       Unit operation--within these operating limits is addressed:'in individual specifications.
DOSE EQUIVALENT 1-131 1.10   DOSE EQUIVALENT 1-131 shall be that concentration of 1-131 (microcuries per gram) which alone would produce the same thyroid dose as the quantity and isotopic mixture of 1-131, 1-132, 1-133, 1-134, and 1-135 actually present. The thyroid dose conversion factors used for this calculation shall be those listed in Federal Guidance Report No. 11 (FGR 11), "Limiting Values of Radionuclide Intake and Air Concentration and Dose Conversion Factors for Inhalation, Submersion and Ingestion".
SALEM - UNIT 2                                1-2               Amendment No. 252

DEFINITIONS E - AVERAGE DISINTEGRATION ENERGY 1.11    E shall be the average (weighted in proportion to the concentration of each radionuclide in the reactor coolant at the time of sampling) of the sum of the average beta and gamma energies per disintegration (in MeV) for isotopes, other than iodines, with half-lives greater than 15 minutes, making up at least 95% of the total non-iodine activity in the coolant.
ENGINEERED SAFETY FEATURE RESPONSE TIME 1.12 The ENGINEERED SAFETY FEATURE RESPONSE TIME shall be that time interval from when the monitored parameter exceeds its ESF actuation setpoint at the channel sensor until the ESF equipment is capable of performing its safety function (i.e., the valves travel to their required positions, pump discharge pressures reach their required values, etc.). Times shall include diesel generator starting and sequence loading delays where applicable.
FREQUENCY NOTATION 1.13 The FREQUENCY NOTATION specified for the performance of Surveillance Requirements shall correspond to the intervals defined in Table 1.2.
FULLY WITHDRAWN 1.13a FULLY WITHDRAWN shall be the condition where control and/or shutdown banks are at a position which is within the interval of 222 to 230 steps withdrawn, inclusive. FULLY WITHDRAWN will be specified in the current reload analysis.
GASEOUS RADWASTE TREATMENT SYSTEM 1.14 A GASEOUS RADWASTE TREATMENT SYSTEM is any system designed and installed to reduce radioactive gaseous effluents by collecting primary coolant system offgases from the primary system and providing for delay or holdup for the purpose of reducing the total radioactivity prior to release to the environment.
IDENTIFIED LEAKAGE 1.15   IDENTIFIED LEAKAGE shall be:
: a. Leakage (except Reactor Coolant Pump Seal Water Injection) into closed systems, such as pump seal or valve packing leaks that are captured and conducted to a sump or collecting tank, or SALEM -  UNIT 2                       1-3                     Amendment No. 276

DEFINITIONS
: b. Leakag e'into the containment atmosphere from sources that are both specifically lodated and known either not t6 interfere       with the operation of leakage, detection systems or not to be PRESSURE BOUNDARY LEAKAGE, or
: c. Reactor coolant system leakage.through a. steam generator to the secondary system (primary-to-secondary leakage)
MEMBER-(S)  OF THE PUBLIC 1.1,6 MEMBER-(S) OF THE<-PUBLIC shall be all those persons, who are not occupati&#xfd;onri&#xfd;y-associated with the plant.- This category doesrinot include employees of PSE&G,i'ts &#xfd;contractfs, 'or vendors.' Also&excluded from this category are persons who enter the site     to service equipment or to make deliveries. This category does include persons who use portions of the site          for recreational, occupational, or other purposes not associated-with'the'plant.
OFFSITE DOSE CALCULATION. IMANUA&#xfd;LL (&#xfd;ODCM)         -
1.17 The OFFSITE DOSE CALCULATION MANUAL      (ODCM) shall contain the methodology and parameters used in the calculation of offsite doses resulting !-,from radioactive gaseous and liquid effluents, in the calculation of gaseous and liquidJe- flwent, monitoring&#xfd;-Alarm/Tzip Setpoints, and, in**the.&#xfd; conduct ofthe Environmental Radfologidal--Monitoring Program.       The ODCM.shall- also. contain (l) the Radioactive Efflueith controls. andRidi'olgical Environmental Monitoring programs required by Section 6.8.4 and (2) descriptions of the, informati'on that should be included in the Annual Radiological Environmental Operating and Annual Radioactive Effluent Release Reports required by Specifications 6.9.1.7 and 6.9.1.8 respectively.
OPERABLEl    OPERABILITY 1.18 A system, subsystem, train, component or device shall be OPERABLE.or have OPERABILITY when' it is capable of performing its specified safety function(s),
and when all necessary attendant instrumentation, controls, normal or emergency electrical power source, cooling and seal water, lubrication or other auxiliary equipment that are required for the system, subsystem, train, comporinnt &#xfd;or device to perform its specified safety function(s) are also capable of performing their related support function(s).
OPERATIONAL MODE - MODE 1.19   An OPERATIONAL MODE   (i.e., MODE)   shall correspond to any'one inclusive combination of core reactivity condition, power level and average reactor coolant temperature specified in Table 1.1.
SALEM - UNIT 2                          1-4                        Amendment No. 262

DEFINITIONS PHYSICS TESTS 1.20   PHYSICS TESTS shall be those tests performed to measure the fundamental nuclear characteristics of the reactor core and related instrumentation and 1) described in Chapter 14 of the Updated FSAR, 2) authorized under the provisions of 10CFR50.59, or 3) otherwise by the Commission.
PRESSURE  BOUNDARY LEAKAGE 1.21   PRESSURE BOUNDARY LEAKAGE shall be leakage (except primary-to-secondary leakage) through a non-isolable fault in a Reactor Coolant System component body, pipe wall or vessel wall.
PROCESS CONTROL PROGRAM   (PCP) 1.22 The PROCESS CONTROL PROGRAM (PCP) shall contain the current formulas, sampling, analyses, test,   and determinations to be made to ensure that processing and packaging of solid radioactive wastes based on demonstrated processing of actual or simulated wet solid wastes will be accomplished in such a way as to assure compliance with 10 CFR Parts 20, 61, and 71, State regulations, burial ground requirements, and other requirements governing the disposal of radioactive waste.
PURGE -  PURGING 1.23   PURGE or PURGING shall be the controlled process of discharging air    or gas from a confinement to maintain temperature, pressure, humidity, concentration, or other operating condition, in such a manner that replacement air  or gas is required to purify the confinement.
QUADRANT POWER TILT RATIO 1.24   QUADRANT POWER TILT RATIO shall be the ratio of the maximum upper excore detector calibrated output to the average of the upper excore detector calibrated outputs, or the ratio   of the maximum lower excore detector calibrated output to the average of the lower excore detector calibrated outputs, whichever is greater. With one excore detector inoperable, the remaining-three detectors shall be used for computing the average.
RATED THERMAL POWER 1.25 RATED THERMAL POWER shall be a total    reactor core heat  transfer rate to the reactor coolant of 3459 MWt.
SALEM - UNIT 2                        1-5                       Amendment No. 262

DEFINITIONS REACTOR TRIP SYSTEM RESPONSE TIME 1.26  The REACTOR TRIP SYSTEM RESPONSE TIME shall be the time interval from when the monitored parameter exceeds its    trip setpoint at the channel sensor until  loss of stationary gripper coil voltage.
REPORTABLE EVENT 1.27  A REPORTABLE EVENT shall be any of those conditions specified in Section 50.73 to 10CFR Part 50.
SHUTDOWN MARGIN 1.28  SHUTDOWN MARGIN shall be the instantaneous amount of reactivity     by which the reactor is subcritical or would be subcritical from its      present condition assuming all  full length rod cluster assemblies (shutdown and control) are fully inserted except for the single rod cluster assembly of highest reactivity worth which is assumed to be FULLY WITHDPAWN.
SITE BOUNDARY 1.29  The SITE BOUNDARY shall be that line beyond which the land is not owned, leased, or otherwise controlled by the licensee, as shown in Figure 5.1-3, and which defines the exclusion area as shown in Figure 5.1-1.
SOLIDIFICATION 1.30   Not Used SOURCE CHECK 1.31   SOURCE CHECK shall be the qualitative assessment of channel response when the channel sensor is exposed to either (a) an external source of increased radioactivity, or(b) an internal source of radioactivity (keep-alive source), or (c) an equivalent electronic source check STAGGERED TEST.BASIS 1.32   A STAGGERED TEST BASIS shall  consist of:
: a. A test  schedule for (n) systems, subsystems, trains, or other designated components obtained by dividing the specified test interval into (n) equal subintervals.
SALEM - UNIT 2                          1-6                    Axnendment No. 263

DEFINITIONS
: b. The testing of one system, subsystem, train, or other designated component at the beginning of each subinterval.
 -IgNS&AL  POWER 1.33     THERMAL POWER shall be the total reactor core heat transfer rate to the reactor coolant.
UNIDENTIFIED LEAKAGE 1.34     UNIDENTIFIED LEAKAGE shall be all Seal Water Injection) which is leakage  (except Reactor Coolant Pump not IDENTIFIED LEAKAGE.                            I URESTRICTED AREA 1.35     An UNRESTRICTED AREA shall be any area at or beyond the SITE BOUNDARY, access to which is not controlled by the licensee for purposes of protection of individuals from exposure to radiation and radioactive materials, or any area within the SITE BOUNDARY used for residential quarters or industrial, commercial, institutional, and/or recreational purposes.
VENTILATION EXHAUST TI1EATMENT SYSTEM 1.36 AVENTILATION EXHAUST TREATMENT SYSTEM shall be any system designed and installed to reduce gaseous radioiodine and radioactive material in particulate form in effluents by passing ventilation or vent exhaust gases through charcoal adsorbers and/or HEPA filters for the purpose of removing iodines or particulate, from the gaseous exhaust stream prior to the release to the environment (such a system is not considered to have any effect on noble gas effluents).      Engineered Safety Feature (ESP) atmospheric cleanup systems are not considered to be VENTILATION EXHAUST TREATMENT SYSTEM components.
1.37    VENTING shall be the controlled process of discharging air or gas from a confinement     to maintain temperature, pressure,   humidity, concentration,  or other operating condition,    in such a manner that replacement air or gas is not provided or required during VENTING.       Vent,  used in system names,  does not imply a VENTING process.
SALEM - UNIT 2                            1-7                       Amendment No.159

DEFINITIONS TABLE 1.1 OPERATIONAL MODES REACTIVITY                            AVERAGE C0OLANT MODE,                       CONOITION, Kefi      THERMAL POWER'        TEMPERATUJRE-I1. PodW    'oPERATiom                                              2. 3506F
                                     >5
: 2. STARTUP                                                          >.35O*F
: 3. HOT STANODBT             <0.9                   0             >.350OF
: 4. HOT  HUTDOWN              <0.99 350-T > Tayg 5.,,COLD SUTDOWN
                                +++*+*++*,,
                                     * ++ ++ . ..                     &#xa3;200*F 5.REFUELING"
    - cluding 4aicy heat.
 "  Fuel in the reactor vessel with the vessel head closure bolts less than fully.
tensloned-,1or with the head removed.
SALEM - UNtT Z                           1-8            Amencenmt No. 28

DEFINIT IONS TABLE 1.2 FREQUENCY NOTATION NOTATION                             FREQUENCY S                         At least once per 12 hours.
0                         At least once per 24 hours.
w At least once per    7 days.
M At least once per 31 days.
At least once per 92 days.
SA                        At least once per    6 months; R                         At least once per IS months.
S/U Prior to each reactor startup.
P                         Prior to each release.
N.A.                      Not applicable.
SALEM - UNIT 2        1-9
                       -              Amendment No. 28
: 2. 0   SMfTT LDTS AM~ L~aT~,        JSAflTr SYSTEK SZTTDIGI 2.1    SI.&AJIY   ,2 S 2.1.1 The combination of T *n.TL PON=ER, pressurizer pressui.e, and the highe*t operating loop Coolant temperature (T,M) shall not exoeed the limit. shmm in Figguire 2.1-1 for 4 loop peatji..n AM;M            M    M=DS I and 2.
Whenever the point defined by the combination of the highest "rpeating loop average temperature and T.MR1,L POR has exceed.e the appropriate pressurize:
pressure line, be in HOT S!4*      T within I hour.
S rkIM- 1Htri 2                        2-1               Amendment mo.197 21AedetW.                       9

680 Q.
_ (0.02, 663.84)                                      UNACCEPTABLE OPERATION 2440 PSIA                                                     LL oOZ 0
0:
U-.*
640 -
u-.-*
DNB 6200 ce.                                                                                                        Z.
i 600 -I-594.31) ~*W W,-
2 0) 580 +           ACCEPTABLE                                      (1.20, 582.81)
OPERATION                                                                572.90) 565.72)
J1     I...I        I1I    L L  I I a    a  a  a  a(1.301I 560
                      .2        .4.4             .6          .8        1          1-.2     1.4 0
FRACTION OF RATED THERMAL POWER FIGURE 2.1.-i       REACTOR CORE SAFETY LIMIT - FOUR LOOPS IN OPERATION SALEM - UNIT 2                                      2-2                        Amendment No. 224 0
: 2. 0   SAflTT LnaT3 AM LDCTflG SAFETY SYSTZH( SZTT3MrS 2.2. SAFETY L2=S RE..ACTOR C29LAM! STASTEI(PhSS 2.1.2    The Reactor Coolant System pressure shall not exceed 2735 psig.
Z    L*",      : -CMhS   1, 2, 3, 4 and 5.
  )CCU 1 and 2 Whenever   the Reactor Coolant System pressuze has exceeded 2735 psig, be in HOT STAMBY with the Reactor Coolant System pressure vw.thn its      limit vithin I.hour.
ODES 3, 4 and 5 Whenievex the Reactor Coolant System pressure has exceeded 2735 pa+/-g, reduce the Reactor Coolant System pressure to within its   limit wit:Ln 5 ninutes.
0 SAZM - VMT 2                             2-3          Amendment No. 197

2.2  LIMITING SAFETY SYSTEM SETTINGS REACTOR TRIP SYSTEM INSTRUMENTATION SETPOINTS 2.2.1 The reactor trip system instrumentation setpoints shall be set consistent with the Trip Setpoint values shown in Table 2.2-1.
APPLICABILITY:  As shown for each channel in  Table 3.3-1.
ACTION:
With a reactor trip system instrumentation setpoint less conservative than the value shown in the Allowable Values column of Table 2.2-1, declare the channel inoperable and apply the applicable ACTION statement requirement of Specification 3.3.1.1 until the channel is restored to OPERABLE status with its trip I
setpoint adjusted consistent with the Trip Setpoint value.
0 SALEM - UNIT 2                2-4              Amendment No. 206 6

TABLE 2.2-1 REACT OR TRIP SYSTEM INSTRUMENTATION      TRIP SETPOINTS FUNCTIONAL UNIT                      TRIP SETPOINT                           ALLOWABLE VALUES
: 1. Manual Reactor Trip             Not applicable                          Not applicable
: 2. Power Range,  Neutron Flux     Low setpoint -     S 25 % of RATED      Low Setpoint -
* 26% of RATED THERMAL POWER                           THERMAL POWER High Setpoint    -   5 109% of RATED    High Setpoint  -  5 110% of RATED THERMAL POWER                           THERMAL POWER
: 3. Power Range, Neutron Flux,     <  5% of RATED THERMAL POWER with       5 5.5% of RATED THERMAL POWER High Positive Rate             a time constant &#x17d; 2 second              with a time constant &#x17d; 2 second
: 4. Deleted I
: 5. Intermediate Range,  Neutron   <  25% of RATED THERMAL POWER              30% of RATED THERMAL POWER Flux
: 6. Source Range,  Neutron Flux       l 0jS counts per second                 1.3 x 105 counts per second
: 7. Overtemperature AT              See Note 1                             See Note 3
: 8. Overpower AT                    See Note 2                             See Note 4
: 9. Pressurizer Pressure--Low         1865 psig                               1855 psig
: 10. Pressurizer Pressure--High     <  2385 psig                               2395 psig
: 11. Pressurizer Water Level--         92% of instrument span                  93% instrument span High
: 12. Loss of Flow                     > 90% of design flow per loop*            89% of design flow per loop*
 *Design flow is   82,500 gpm per lo SALEM - UNIT 2                                         2-5                                    Amendment No. 261

TABLE 2.2-1  (Continued)
REACTOR TRIP SYSTEM INSTRUMENTATION TRIP SETPOINTS FUNCTIONAL UNIT                    TRIP SETPOINT                        ALLOWABLE VALUES
: 13. Steam Generator Water Level--Low-Low
                                   &#x17d; 14.0% of narrow range instrument span-each steam generator 2:13.0% of narrow range instrument span-each steam generator I
: 14. Deleted
: 15. Undervoltage-Reactor          &#x17d; 2900 volts-each bus                   2850 volts-each bus Coolant Pumps
: 16. Underfrequency-Reactor        2 56.5 Hz -  each bus                   56.4 Hz -  each bus Coolant Pumps
: 17. Turbine Trip A. Low Trip System              45 psig                               45 psig Pressure B. Turbine Stop Valve           15% off full open                   : 15% off full open Closure
: 18. Safety Injection Input        Not Applicable                        Not Applicable from ESF
: 19. Reactor Coolant Pump          Not Applicable                        Not Applicable Breaker Position Trip SALEK - UNIT 2                                    2-6                                       Amendment No.238 I

TABLE 2.2-1     (Continued)
REACTOR TRIP SYSTEM INSTRUMENTATION           TRIP SETPOINTS NOTATION NOTE 1:    Overtemperature           AT < AT.     [KF-K, 1+T181(T-T)+K,(P-P'--f,(AI) I
                                                        .- t where:      AT    w Indicated       AT at   RATED THERMAL POWER 0
T     - Average      temperature.     *F T1    w Reference       T.,. at  RATED THERMAL POWER <      577.9 0 F P     - Pressurizer pressure,           psig PI    - 2235 psig       (indicated RCS nominal operating pressure)
                       =  The function generated by the lead-lag controller for I+ -rS T3 ,, dynamic compensation TI & T2 = Time constants utilized in the lead-lag controller for Tn       T,  = 30 secs    +/-10%,  T2 = 4 secs.    +/-10%
I S     = Laplace transform operator,           Sec' SALEM  - UNIT 2                                                   2-7                              Amendment No. 220

TABLE 2.2-1 (Continued)
REACTOR TRIP SYSTEM INSTRUMENTATION TRIP SETPOINTS NOTATION (Continued)
Operation with 4 Loops K,      1.22 K2 -    0.02037 KX 3  -   0.001020 and f, (AI) is a function of the indicated difference between top and bottom detectors of the power-range nuclear ion chambers; with gains to be selected based on measured instrument response during plant startup tests such that:
(i)      for q, - q. between -33 percent and +11 percent, f, (AI) = 0 where q, and q, are percent RATED THERMAL POWER in the top and bottom halves of the core respectively, and q, + q6 is total THERMAL POWER in percent of RATED THERMAL POWER).
(ii)     for each percent that the magnitude of (q, - qb) exceeds -33 percent, the AT trip setpoint shall be automatically reduced by 2.34 percent of its value at RATED THERMAL POWER.
(iii)    for each percent that the magnitude of (q,- q,) exceeds +11 percent, the AT trip setpoint shall be automatically reduced by 2.37 percent of its value at RATED THERMAL POWER.
SALEM - UNIT 2                             2-a               Amendment No. 224

TABLE 2.2-1     (Continued)
REACTOR TRIP SYSTEM INSTRUMENTATION TRIP SETPOINTS NOTATION    (Continued)
NOTE 1:   Overpower           AT        [K-Ks   [IS1T     -   K 6 (T-T"}f&#x17d;(AI)J where:       AT     -    Indicated AT at RATED THERMAL POWER 0
T     a   Average temperature,     OF 0
TO -      Reference T.,. at RATED THERMAL POWER      < 577.9   F K, -    1.09 K, -    0.02/*F for increasing average temperature           and 0 for decreasing average temperature K,-     0.00149/OF for T > T"; K, = 0 for T : Te rjS      = The function generated by the rate lag controller for 1+TS          Tvg dynamic compensation 3     Time constant utilized       in the rate lag controller for Tavq [t = 10 secs. +/-10%
S    =   Laplace transform operator, Sec'.
f 2 (AI)         0 for all   AI Note 3:  The channel's maximum trip          point shall not exceed its        computed trip   point by more than 1.1 percent.
Note 4:  The channel's maximum trip          point shall not exceed its        computed trip   point by more than 2.1 percent.
SALEM - UNIT 2                                                  2-9                            Amendment No. 220
:.I SAFETY L2{IaTS EASE S 2.1.1 REACTOR CORE The restrictions of this safety limit prevent overheating of the fuel and possible cladding perforation which would result in the release of fission
;:roducts to the reactor coolant. Overheating of the fuel cladding is prevented by restricting fuel operation to within the nucleate boiling regime where the beat transfer coefficient is large and the cladding surface temperature is slightly above the coolant saturation temperature.
Operation above the upper boundary of the nucleate boiling regime could result in excessive cladding temperatures because of the onset of departure from nucleate boiling (DG) and the resultant sharp reduction in heat transfer coefficient. DNB is not a directly measurable parameter during operation and therefore THERMAL POWER and Reactor Coolant Temperature and Pressure have been related to DNB through correlations which have been developed to predict the DKB flux and the location of DNB for axially uniform and non-uniform heat flux distributions. The local DNS heat flux ratio, DN3R, decided as the ratio of the heat flux that would cause DNB at a particular core location to the local heat flux, is indicative of the margin, to DNB.
The DNB design basis is as followsi uncertainties in the WRB-I and WRB-2 correlations, plant operating parameters, nuclear and. thermal parameters, fuel fabrication parameters, and computer codes are considered statistically such thiat there is at least a, 95 percent probability with 95 percent confidence level that DNER will not occur on the most limiting fuel rod during Condition I and 11 events. This establishes a design DNBR value which must be met in plant safety analyses using values of input Parameters without uncertainties.
The curves of rigure 2.1-1 shows the loci of points of THERMAL -POWER, Reaactor Coolant System pressure and-average temperature for which the minimum D:>-R is no less than the design DNBR value, or the average enthalpy at the vassel exit is equal to the enthalpy of saturated liquid.
The cu.rves are based on an enthalpy hot channel factor, F=aa         and a reference cosine with a peak of 1.55 for axial power shape. An allowance is included for an increase in r*          at reduced power based on the expresszon:
F'M -   F37   [.0     + P'   (1.0 -  P)]
Where:    F    jL,*.;imit       at RATED THERMAL POWER in   the Core Operating Limits Report (COLR).
PF, is the Power Factor Multiplier for       eAX  specified in the COLR, -and P is        MMORL9L POWER RATED THERMAL POWER These limiting heat flux conditions are higher than those calculated for the range of all control rod positions from FULLY WITHDRAWN to tie maximum allowable control rod insertion assuming the axial power inbalance is within the limits of the f         (delta 1) function of the Overtemperature trip.        When the axial power SKZM - UNIT 2                               B 2-1                Amendment No.197

SAFETY LIMITS BASES imbalaince is, not ,wlth'ifltheC                  tolerance,.                  the axial power-imbalIance. off ecton the Qvet         eratUedeltoaT                 tri.p.s Wi               reduce. the. setpoints to proyide protection conitn             ith core saf                            mit..1,1..
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SALEM - UNIT 2                                                      8 2-2
: 2. IMITING  AESXTYYTMSETTINGS BASES 2.2.'l REACTOR TRIP SYSTEM INSTRUMENTATION SETPOINTS The Trip Setpoints are the nominal values at which the bistables are set.
Any bistable is considered to be properly adjusted when the "as-left" value is within the band for CHANNEL CALIBRATION accuracy (i.e., +/- rack calibration +
comparator setting accuracy).
The Trip Setpoints used in the bistab]es are based on the analytical limits stated in the UFSAR. The selection of these Trip Setpoints is such that adequate protection is provided when all sensor and processing time delays are taken into account. To allow for calibration tolerances, instrumentation uncertainties, instrument drift, and severe environment errors for those Reactor Protection System (RPS) channels that must function in harsh environments as defined by 10 CFR 50.49, the Trip Setpoints and Allowable Values specified in the Technical Specification Limiting Conditions for Operation (LCO's) are conservatively adjusted with respect to the analytical limits. The methodology used to calculate the Trip Setpoints is consistent with Instrument Society of America standard ISA-S67.04-1982, which is endorsed via NRC Regulatory Guide 1.105, Rev. 2.      The actual nominal Trip Setpoint entered into the bistable is more conservative than that specified by the Allowable Value to account for changes in random measurement errors detectable by a CHANNEL FUNCTIONAL TEST. one example of such a change in measurement error is drift during the surveillance interval.      If the measured setpoint does not exceed the.Allowable value, the bistable is considered OPERABLE.
Setpoints in accordance with the Allowable Value ensure that the safety analyses which demonstrate that safety limits are not violated remain valid (provided the unit is operated within the LCO's at th= onset of any design basis event and the equipment functions as designed).
The Trip Setpoints and Allowable Values listed in the LCO's incorporate all of the known uncertainties applicable for each channel.      The magnitudes of these uncertainties are factored into the determination of each Trip Setpoint.
All field sensors and signal processing equipment for these channels are assumed to operate within the allowances of these uncertainty magnitudes.
Manual Reactor Trip The Manual Reactor Trip is a redundant channel to the automatic protective instrumentation channels and provides manual reactor trip capability.
Power Rance,    Neutron Flux The Power Ranae, Neutron Flux channel high setpoint provides reactor core protection against reactivity excursions which are too rapid to be protected by temperature and pressure protective circuitry. The low set point provides redundant protection in the power range for a power excursion beginning from low power. The trip associated with the low setpoint may be manually bypassed when P-10 is active (two of the four power range channels indicate a power level of above approximately 9 percent of RATED THERMAL POWER) and is auto-SALEM - UNIT 2                        B 2-3                     Amendment U-j. 140

LIMITING   SAFETY SYSTEM  SETTINGS BASES matically reinstated when P-10 becomes inactive (three of the four channels indicate a power level below approximately 9 percent of RATED THERMAL POWER).
Power Range,    Neutron Flux,   High Rate The Power Range Positive Rate trip      provides protection against rapid flux 'increases which aie characteristic of rod ejection events from any power level. Specifically, this      trip  d6mpiem6nts the Power Range Neutron Flux High and Low tz-ips 'to ensure that the criteria       are met for rod ejection from partial power.
Intermediate. and Source Range,     Nuclear Flux The Intermediate and Source Range, Nuclear Flux trips        provide reactor core protection during reactor star~tup.        These, trips  provide redundant protection' to the low setpoint 'trip     of the Power Range, Neutron Flux chan-hi'el.'    The Source Range Channel's will initiate       a reactor trip   at about 10" counts."per second unless 'ma alI'yI' block(d when P-6 beccmes* actike. :,Th'e Thtermediat6&
Rhag,,'Channels will :*initiate a reactor trip 'at a 'current level- proportional to'- approximately 25" percent of RATED THERMAL -POWER unless, manually; blocked when P-10 becomes-active.        No -credit was taken. for, operation of the, trips associated- with either the Intermediate or Source Range Channels in the, accident analyses; however, their functional capability at the specified trip settings is required by this specification to enhance the overall reliability of the Reactor Prote~ction System.
Overtemperature A-T The Overtemperature A T trip provides core protection to prevent DNB for all combinations of pressure;d power, coolant temperature, - and. axial power distribution, provided that the -transient is. slow with, respect to piping transit delays: from the core to the temperature detectors (about; 4.seconds),
and pressure is within the range between the High and Low Pressure, reactor trips,. This setpoint includes corrections for changes in density and heat capacity of"water with temperature and dynamic compensation for piping delays from the core to the loop temperature detectors.           With normal axial power distribution, this reactor trip limit is always below the core safety limit as shown in Figure 2.1-1.        If axial peaks are greater than design, as indicated, by the difference between top and bottom power, range nuclear detectors, the reactor trip is automatically reduced according to the notations in    Table 2.2-1.
SALEM -    UNIT 2                          B 2-4                     Amendment No. 261 (PSEG Issued)

LIMITING SAFETY SYSTEM SETTINGS BASES Operation with a reactor coolant loop out of service below the 4 loop P-8 setpoint does not require reactor protection system setpoint modification because the P-8 setpoint and associated trip will prevent DNB during 3 loop operation exclusive of the Overtemperature delta T setpoint. Three loop operation above the 4 loop P-8 has not been evaluated and is not permitted.
Overpower Delta T The Overpower delta T reactor trip provides assurance of fuel integrity, e.g., no melting, under all possible overpower conditions, limits the required range for Overtemperature delta T protection, and provides a backup to the High Neutron Flux trip. The setpoint includes corrections for changes in density and heat capacity of water with temperature, and dynamic compensation for piping delays from the core to the loop temperature detectors. As a result of the new AREVA steam generators, credit is taken for the operation of this trip in the accident analyses for the protection of the reactor core following a main steam line break.
Pressurizer Pressure The Pressurizer High and Low Pressure trips are provided to limit the pressure range in which reactor operation is permitted. The High Pressure trip is backed up by the pressurizer code safety valves for RCS overpressure protection, and is therefore set lower than the set pressure for these valves (2485 psig) . The Low Pressure trip provides protection by tripping the reactor in the event of a loss of reactor coolant pressure.
Pressurizer Water Level The Pressurizer High Water Level trip ensures protection against Reactor Coolant System overpressurization by limiting the water level to a volume sufficient to retain a steam bubble and prevent water relief through the pressurizer safety valves. No credit was taken for operation of this trip in the accident analyses; however, its   functional capability at the specified trip setting is required by this specification to enhance the overall reliability of the Reactor Protection System.
SALEM - UNIT 2                       B 2-5            Amendment No. S2010-119 (PSEG Issued)

L:2.aTING SAFETY SYSTE    SETTINGS BASES
 .css of Flow The Loss of Flow trips provide core protection to prevent DNB in        the event of a loss of one or zore reactor coolant pimp8.
Above ii percent of RATED TIZFMAL POnER, an automatic reactor trip will occur   if the flow in any two loops drop below 90% of no-ins.. full loop fl*v. Above 36% (P-8) of RAM THERMAL POWER, automatic reactor trip will oc---   if the flow in any single loop drops below 90% of nominal full loop fl w. This latter  trip will prevent the zinimum value of the DNBR from going below   the design DNBR value during normal operational transients.
Staam Generator Water Level The Steam Generator Water Level Low-Low trip provides core protection by prioiventing operation with the steam generator water level below the minimum vo:.ume required for adequate heat removal capacity. The specified setpoint prcovides allowance that there will be sufficient water inventory in the steam generators at the tim of trip to allow for starting delays of the auxiliary feudwater system.
SAZI:M - UNIT 2                            B 2-6          SALT
                                                              - NXT2     No.-19 7 32-6Amendment

LIMITING SAFETY SYSTEM SETTINGS BASES Undervoltage and Underfrequency   - Reactor Coolant Pump Busses The Undervoltage and Underfrequency Reactor Coolant Pump bus trips provide reactor core protection against DNB as a result of loss of voltage or underfrequency to more than one reactor coolant pump. The specified set points assure a reactor trip signal is generated before the low flow trip set point is reached. Time delays are incorporated in the underfrequency and undervoltage trips to prevent spurious reactor trips from momentary electrical power transients. For undervoltage, the delay is set so that the time required for a signal to reach the reactor trip breakers following the simultaneous trip of two or more reactor coolant pump bus circuit breakers shall not exceed 0.9 seconds.
For underfrequency, the delay is set so that the time required for a signal to reach the reactor trip breakers after the underfrequency trip set point is reached shall not exceed 0.3 seconds.
Turbine Trip A Turbine Trip causes a direct reactor trip when operating above P-9. Each of the turbine trips provide turbine protection and reduce the severity of the ensuing transient. No credit was taken in the accident analyses for operation of these trips. Their functional capability at the specified trip settings is required to enhance the overall reliability of the Reactor Protection System.
Safety Injection Input from ESF If a reactor trip has not already been generated by the reactor protective instrumentation, the ESF automatic actuation logic channels will initiate a reactor trip upon any signal which initiates a safety injection. This trip is provided to protect the core in the event of a LOCA. The ESF instrumentation channels which initiate a safety injection signal are shown in Table 3.3-3.
Reactor Coolant Pump Breaker Position Trip The Reactor Coolant Pump Breaker Position Trip is an anticipatory trip which provides reactor core protection against DN4 resulting from the opening of two or more pump breakers above P-7. This trip is blocked below P-7. The open/close position trip assures a reactor trip signal is generated before the low flow trip set point is reached. No credit was taken in the accident analyses for operation of this trip. The functional capability at the open/close position settings is required to enhance the overall reliability of the Reactor Protection system.
SALEM - UNIT2                         B 2-7            Amendment No. 60

5.0 DESIGN FEATURES 5.1   SITE EXCLUSION AREA S.1.1   The exclusion area shall be shown in Figure 5.1.1 LOW POPULATION ZONE 5.1.2 The low population zone shall be as shown in Figure 5.1-2.
UNRESTRICTED AREAS FOR RADIOACTIVE GASEOUS AND LUQUIO EFFLUENTS 5.1.3 UNRESTMICTED AREAS within the SITE BOUNDARY that are accessible to MEMBERS OF THE PUBLIC, shall be as shown in Figure S.1-3.
.5.2 CONTAINMENT CONFIGURATION 5.2.1 The reactor containment building is a steel lined, reinforced concrete building of cylindrical shape,.with a dome roof and- having the following design features:
: a. Nominal inside diameter a .140 feet.
: b. Nominal inside height a 210 feet.
: c. Minimum thickness of concrete walls - 4.5 feet.'
: d. Minimum thickness of concrete roof a 3.5 feet.
: e. Minimum thickness of concrete floor mat a 16 feet.
: f. Nominal thickness of steel liner - 1/4 to 1/2 inch.
        ;. Net free volume - 2.62 x 106 cubic feet.
SALEM - UNIT 2                           5-1          2Amendment No. 28

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U~12 53   a No. 28

DESIGN FEATURES DESIGN PRESSURE AND TEMPERATURE 5.2.2    The reactor containment is designed and shall be maintained for a maximum, internal pressure of 47 psig., Containment air temperatures up to 351.3*F are acceptable providing the containment pressure is in accordance with that described in the UPSAR.
5.3&#xfd; REACTOR CORE FUEL ASSEMBLIES 5.3.1     The reactor core shall contain 193 fuel assemblies. Each assembly shall consist. of a matrix of zircaloy or ZI2RLO clad fuel rods with an initial composition of natural or slightly enriched uranium dioxide as fuel material. Limited substitutions of zirconium alloy or stainless steel filler rods for fuel rods, in accordance with NRC-approved applications of fuel rod configurations, may be used. Fuel assemblies shall be limited to those fuel designs that have been analyzed with applicable NRC staff approved codes and methods and shown by tests or analyses to comply with all fuel safety design bases. A.limited number of lead test assemblies that have not completed representative testing may be placed in nonlimiting core regions.
CONTROL'ROD ASSEMBLIES 5.3.2    The reactor core shall contain 53 full length and no part length control rodtassemblies. The,,full .length control rod assemblies shall Scon tain~anoxninal 142 inches of absorber material. The nominal values Soabsorber m'terial shall be 80 'percent silver, 15 percent indium and
          -5',percenrt'CadmIum. All control rods shall be clad with stainless steel tubing.,
5.4   REACTOR COOLANT SYSTEM DESIGN PRESStmE ANDl TEMPERATURE 5.4.1     The reactor coolant system is designed and shall be maintained:
: a. In accordance with the code requirement specified in Section 4.1 of the FSAR, with-,allowance for normal degradation pursuant to the applicable Surveillance Requirements,
: b.       For a pressure of 2485 psig, and.
: c.      'For a temperature of 650 0 F, except for the pressurizer which is 680 0 F.
SALEM - UNIT 2                               5-4                   Amendment No. 25M

DESIGN FEATURES 5.5   METEOROLOGICAL TOWER LOCATION 5.5.1   The meteorological tower shall be located as shown on Figure 5.1-1.
5.6   FUEL STORAGE CRITICALITY 5.6.1.1      The new fuel storage racks are designed and shall be maintained with:
: a. A maximum KXf equivalent of equal to 0.95 with the storage racks flooded with unborated water.
: b. A nominal 21.0 inch center-to-center  distance between fuel assemblies.
: c. Unirradiated fuel assemblies with enrichments less than or equal to 4.25 weight percent (w/o) U-235 with no requirements for Integral Fuel Burnable Absorber (IFBA) pins.
: d. Unirradiated fuel assemblies with enrichments (E) greater than 4.25 w/o U-235 and less than or equal to 5.0 w/o U-235 which contain a minimum number of Integral Fuel Burnable Absorber (IFBA) pins. This minimum number of IFBA pins shall have an equivalent reactivity hold-down which is greater than or equal to the reactivity hold down associated with N IFBA pins, at a nominal 2.35 mg B-10/linear inch loading (1.5X), determined by the equation below:
N = 42.67 ( E -  4.25 5.6.1.2      The spent fuel storage racks are designed and shall be maintained with:
: a. A maximum Keff equivalent of 0.95 with the storage racks filled with unborated water.
: b. A nominal 10.5 inch center-to-center distance between fuel assemblies stored in Region I (flux trap type) racks.
: c. A nominal 9.05 inch center-to-center distance between fuel assemblies stored in Region 2 (non-flux trap) racks.
SALEM - UNIT 2                        5-5                      Amendment No, 244

DESIGN FEATURES This Page is Intentionally Blank SALEM - UNIT 2               5-5a                Amendment No.244

DESIGN FEATURES DRAINAGE 5.6.2 The spent fuel storage pool is designed and shall be maintained to prevent inadvertent draining of the pool below elevation 124811.
CAPACITY 5.6.3 The spent fuel storage pool is designed and shall be maintained with a storage capacity limited to no more than 1632 fuel assemblies.
5.7  COMPONENT CYCLIC OR TRANSIENT LIMIT 5.7.1 The components identified in Table 5.7-1 are designed and shall be maintained within the cyclic or transient limits of Table 5.7-1.
SALEM - UNIT 2                      5- 5b                     Amendment No. 244

(Ah TABLE 5.7-1 COMPONENT CYCLIC OR TRANSIENT LIMITS
'-4 CYCLIC OR                                DESIGN CYCLE COMPONENT                     TRANSIENT LIMIT                             OR TRANSIENT Reactor Coolant System 200 heatup cycles at < 100*F/hr         Heatup cycle - T      from < 200OF and 200 cooldown cycles at              to > 5426F.      avg
                            < 100&deg;F/hr (pressurizer cooldown        CooTdown cycle - T       from > 542*F it < 200&deg;F/hr).                         to < 2000 F.       avg        -
80 loss of load cycles.                 Without immediate turbine or reactor trip.
40 cycles of loss of offsite            Loss of offsite A.C. electrical A.C. electrical power.                  power source supplying the onsite
  $"                                                                Class IE distribution system.
80 cycles of loss of flow in one Loss of only one reactor reactor coolant loop.                   coolant pump.
400 reactor trip cycles.                100% to 0% of RATED THERMAL POWER.
200 large step decreases                50% of RATED THERMAL POWER step in load.                                load decrease with steam dump.

r-TABLE 5.7-1 (Continued) m COMPONENT CYCLIC OR TRANSIENT LIMITS C
CYCLIC OR                               DESIGN CYCLE r   COMPONENT                     TRANSIENT LIMIT                            OR TRANSIENT Reactor Coolant System 1 main reactor coolant pipe break.      Break in a reactor coolant pipe
                                                                   > 13.5 inches equivalent diameter.
Operating Basis Earthquake 50 cycles Design Basis Earthquake                 10 cycles; 0.20g horizontal,    0.136g vertical.
50 leak tests.                          Pressurized to > 2485 psig.
5 hydrostatic pressure tests            Pressurized to > 3107 psig.
 -! Secondary System       1 steam line break                      Break in a steam line > 6 inches equivalent diameter.
5 hydrostatic pressure tests            Pressurized to > 1356 psig.
10 turbine roll tests                   Turbine roll on pump heat resulting in plant cooldown > 100 0 F/hr.
I&

ADMINISTRATIVE     CONTROLS 6.1   RESPONSIBILITY 6.1.1 The plant manager shall be responsible for overall facility operation and shall delegate in writing the succession to this responsibility during his absence.
6.1.2 The Senior Nuclear Shift Supervisor or, during his absence from the Control Room, a designated individual shall be responsible for the Control Room command function.      A management directive to this effect, signed by the senior corporate nuclear officer, shall be reissued to all station personnel on an annual basis.
6.2 ORGANIZATION 6.2.1 ONSITE AND OFFSITE ORGANIZATIONS Onsite and offsite organizations shall be established for unit operation and corporate management, respectively.      The onsite and offsite organizations shall include positions for activities affecting the safety of the nuclear power plant.
: a.      Lines of authority, responsibility, and communication shall be established and defined from the highest management levels through intermediate levels to and including all operating organization positions. These relationships shall be documented and updated, as appropriatei in the form of--organization -charts, functional descriptions of departmental *responsibilities..and. relationships, and job descriptions for key personnel positions, or in equivalent forms of documentation. These requirements shall be documented in the Salem Updated Final Safety Analysis Report and updated in accordance with 10 CFR 50.71(e).
: b.      The plant manager shall be responsible for overall facility safe operation and shall have control over those onsite activities necessary for safe operation and maintenance of the plants.
C.      The senior corporate nuclear officer shall have corporate responsibility for overall plant nuclear safety and shall take any measures needed to ensure acceptable performance of the staff in operating, maintaining, and providing technical support to the plants to ensure nuclear safety.
: d.      The individuals who train the operating staff and those who carry out health physics and quality assurance functions may report to the appropriate onsite manager; however, they shall have sufficient organizational freedom to ensure their independence from operating pressures.
6.2.2     FACILITY STAFF The Facility organization shall be subject to the following:
: a.      Each on duty shift shall be composed of at least the minimum shift crew composition shown in Table 6.2-1.
SALEM - UNIT 2                            6-1                    Amendment No.175

ADMINISTRATIVE CONTROLS FACILITY STAFF    (Continued)
: b. At least one licensed Reactor Operator shall be in the control room when fuel is in the reactor. In addition, at least one licensed Senior Reactor Operator shall be in the Control Room area at all times.
: c. All CORE ALTERATIONS shall be observed and directly supervised by a licensed Senior Reactor Operator who has no other concurrent responsibilities during this 'operation.
SALEM - UNIT 2                       6-2                      Amendment No. 274

Figure 6.2-1   CORPORATE HEADQUARTERS AND OFF-SITE ORGANIZATION FOR MANAGEMENT AND TECHNICAL SUPPORT (Deleted)
SALEM - UNIT 2                           6-3                 Amendment No. 112 1

FIGURE 6.2-2 FACILITY ORGANIZATION (Deleted) 0 SALEM - UNIT 2                         6-4 Amendment No. 112 f

TABLE 6.21 MINIMUM SHIFT CREW COMPOSITION SALEM UNIT 2 WITH UNIT 1 IN MODES 5 OR 6 OR DE-FUELED POSITION                           NUMBER OF INDIVIDUALS REQUIRED TO FILL POSITION MODES 1, 2,  3 & 4                MODES 5 & 6 1I SNSS SRO                                         Ib                               none STA                                         Ib                               none NCO                                         2                                 1 3                                 2c EO/UO Maintenance Electrician                      1                                none Rad. Pro. Technician                         1a                               1 ae WITH UNIT 1 IN MODES 1, 2, 3 OR 4 POSITION                           NUMBER OF INDIVIDUALS REQUIRED TO FILL POSITION MODES 1, 2,  3 & 4                MODES 5 & 6 SNSS                                         Ia                               Ia SRO                                          Ib                               none STA                                          Ib                               none NCO                                          2                                1 EO/UO                                        3d                               1 Maintenance Electrician                      18                               none 1a                               1a Rad. Pro. Technician a/    Individual may fill     the same position on Unit 1.
b/    Individual who fulfills     the STA requirement may fill   the same position on Unit 1.      The STA, if a licensed SRO, may concurrently fill the SRO position on one unit; the other unit also requires a qualified SRO on shift.
c/    one of the two required individuals may fill       the position on Unit 1, such that there are a total of three EO/UO's for both units.
d/    one of the three required individuals may fill       the same position of unit 1, such that there are a total of five EO/UO's for both units.
e/    Not needed if  both reactors are de-fueled.
SALEM - UNIT 2                              6-5                     Amendment No. 112

TABLE 6.2-1 Lgontinuedi SNSS    -  Senior Nuclear Shift Supervisor with a Senior Reactor Operator License on both units.
SRO     -  Individual with a Senior Reactor Operator License on both units (normally, a Nuclear Shift Supervisor ).
NCO     -  Nuclear Control Operator with a Reactor Operator License on both units.
STA     -  Shift Technical Advisor (if licenued as SRO, may be assigned duties as a Nuclear Shift Supervisor).
EO/UO    _ Equipment Operator or Utility Operator.
Except for the Senior Nuclear Shift Supervisor, the Shift Crew Composition may be one less than the minimum requirements of Table 6.2-1 for a period of time not to exceed 2 hours in order to accommodate the unexpected absence of on-duty shift crew members provided that immediate action is taken to restore the Shift Crew Composition to within the minimum requirements of Table 6.2-1.
This provision does not permit any shift crew position to be unmanned upon shift change due to an oncoming shift crewperson's being late or absent.
During any absence of the Senior Nuclear Shift Supervisor from the Control Room area while the unit is in any MODE, an individual with a valid SRO License shall be designated to assume the Control Room command function.
SALEM - UNIT 2                          6-6                    Amendment No.112 I

ADMINISTRATIVE CONTROLS 6.2.3    SHIFT TECHNICAL ADVISOR 6.2.3.1    The Shift Technical Advisor shall serve in an advisory capacity to the Senior Nuclear Shift Supervisor on matters pertaining to the engineering aspects assuring safe operation of the unit.
6.2.3.2    The Shift Technical Advisor shall have a Bachelor's Degree or equivalent in a scientific or engineering discipline with specific training in plant design and response and analysis of the plant for transients and accidents.
6.3   FACILITY STAFF QUALIFICATIONS 6.3.1 Each member of the facility        staff shall meet or exceed the minimum qualifications of ANSI N18.1-1971 for comparable positions, except for the individual designated as the Radiation Protection Manager who shall meet or exceed the qualifications of Regulatory Guide 1.8, September 1975, the individual designated as the Operations Manager who shall meet or exceed the minimum qualifcations of ANSI N18.1-1971 except as modified by Specification 6.3.3, and the licensed operators who shall comply with the requirements of 10CFR55.
6.3.2 The Operations Manager or Assistant Operations Manager shall hold an SRO license.       The Senior Nuclear Shift Supervisors and Nuclear Shift Supervisors shall each hold a senior reactor operator license.           The Nuclear Control Operators shall hold reactor operator licenses.
6.3.3    The Operations Manager shall meet one of the following:
: 1)    Hold an SRO license,    or
: 2)    Have held an SRO license for a similar unit      (PWR),   or
: 3)    Have been certified at an appropriate simulator for equivalent senior operator knowledge.
6.4   TRAINING 6.4.1    A retraining and replacement training program for the facility        staff shall:
: 1) be coordinated by each functional level manager (Department Head) at the facility     and maintained under the direction of the Director - Nuclear Training
: 2) meet or exceed the iequirements and recommendations of Section 5.5 of ANSI N18.1-1971 for all     affected positions except licensed operators and
: 3)  comply with the requirements of 10CFR55 for licensed operators.
SALEM - UNIT 2                            6-7                       EAmendment No. 175

ADMINISTRATIVE       CONTROLS 6.=   R   =======A       ====AD====ITH======          L      = ==
6.5   REVIEW AND AUDIT           (THIS      SECTION DELETED)
Amendment No.1 75 SALEM   -UNIT      2

ADMINISTRATIVE CONTROLS PAGES 6-9 THROUGH 6-14 DELETED SALEM - UNIT 2                      6-9 through 6-14   Amendment No.175

ADMINISTRATIVE CONTROLS THIS PAGE INTENTIONALLY BLANK.
I SALEM - UNIT 2                       6-15              Amendment No. 175

ADMINISTRATIVE    CONTROLS 6.6   REPORTABLE EVENT ACTION 6.6.1    The following actions shall be taken for REPORTABLE EVENTS:
: a. The Commission shall be notified and/or a report submitted pursuant to the requirements of Section 50.73 to 10CFR Part 50, and
: b. Each REPORTABLE EVENT shall be reviewed by the Station Operations Reivew Committee (SORC) and the resultant Licensee Event Report submitted to the Nuclear Review Board and the senior corporate nuclear officer.
6.7   SAFETY LIMIT VIOLATION 6.7.1 The following actions shall be taken in     the event a Safety Limit is violated:
: a. The unit shall be placed in at least HOT STANDBY within one hour.
: b. The NRC Operations Center shall be notified by telephone as soon as possible and in all cases within one hour. The senior corporate nuclear officer and senior management position with responsibility for independent nuclear safety assessment activities and quality program oversight shall be notified within 24 hours.
: c. A Safety Limit Violation Report shall be prepared. The report shall be reviewed by the SORC. This report shall describe (1) applicable circumstances preceding the violation, (2) effects of the violation upon facility components, systems or structures, and (3) corrective action taken to prevent recurrence.
: d. The Safety Limit Violation Report shall be submitted to the Commission, the senior management position with responsibility for independent nuclear safety assessment activities and quality program oyersight and the senior corporate nuclear officer within 14 days of the violation.
Amendment No. 1 75 SALEM - UNIT 2                         6-16

ADMINISTRATIVE CONTROLS 6.8   PROCEDURES AND PROGRAMS 6.8.1 Written procedures shall be established.,    implemented and maintained covering the activities referenced below:
: a. The applicable procedures recommended in Appendix "A" of Regulatory Guide 1.33, Revision 2, February 1978.
: b. Refueling operations.
: c. Surveillance and test activities of safety related equipment.
: d. Security Plan implementation.
: e. Emergency Plan implementation.
: f. Fire Protection Program implementation.
: g. PROCESS CONTROL PROGRAM implementation.
: h. OFFSITE DOSE CALCULATION MANUAL implementation.
: i. Quality Assurance Program for effluent and environmental monitoring.
6.8.2 Each procedure and administrative policy of 6.8.1 above, except 6.8,1.d and 6.8.1.e, and changes thereto, shall be reviewed and approved in accordance with requirements in Updated Final Safety Analysis Report (UFSAR) section 17.2 for SORC or for Technical Review and Control, as appropriate, prior to implementation and reviewed periodically as set forth in administrative procedures. Procedures of 6.8.1.d and 6.8.1.e shall be reviewed and approved in accordance with the Facility's Security and Emergency Plans or requirements in Updated Final SAfety Analysis Report (UFSAR) section 17.2 for Technical Review and Control, as appropriate, prior to implementation and reviewed periodically as set forth in administrative procedures.
6.8.3    On-the-spot changes to procedures of 6.8.1 above may be made provided:
: a. The intent of the original procedure is   not altered.
: b. The change is approved by two members of the pl~nt management staff, at least one of whom holds a Senior Reactor Operator's License on the unit affected.
C. The change is documented and receives the same level of review and approval as the original procedure under within 14 days of implementation.
SALEM - UNIT 2                        6-17                      Amendment No.175

ADMINISTRATIVE CONTROLS 6.8.4    The following programs shall be maintained:
: a. Primary Coolant Sources Outside Containment A program to reduce leakage from those portions of systems outside containment that could contain highly radioactive fluids during a serious transient or accident to as low as practical levels. The systems include (recirculation spray, safety injection, chemical and volume control, gas stripper, recombiners,    ... ). The program shall include the following:
(i)   Preventative maintenance and periodic visual inspection requirements, and (ii)  Integrated leak test requirements for each system at refueling cycle intervals or less.
: b. In-Plant Radiation Monitoring A program which will ensure the capability to accurately determine the airborne iodine concentration in areas under accident conditions. This program shall include the following:
(i)    Training of personnel, (ii)   Procedures for monitoring,   and (iii)  Provisions for maintenance of sampling and analyses equipment.
: c. Secondary Water Chemistry A program for monitoring of secondary water chemistry to inhibit steam generator tube degradation.      This program shall include:
Wi)   Identification of a sampling schedule for the critical variables and the control points for these variables, (ii)   Identification of the procedures used to measure the values of the critical variables, (iii)   Identification of process sampling points, including monitoring at the discharge of the condensate pumps for evidence of condenser in-leakage.
(iv)   Procedures  for zhe recording and management of data, (v)    Procedures defining corrective actions for off-control-point chemistry conditions, SALEM - UNIT 2                            6-18                     Amendment No. 112

ADMZNISTRATIVE CONTROLS (vi)   A procedure ident*fying    (a) the authority responsible for the interpretation of the data, and (b) the sequence and timing of administrative events required to initiate corrective action.
: d. Backup Method for Determining..Subcooling.Margin A program which will ensure the capability to accurately monitor the Reactor Coolant System Subcooling Margin. This program shall include the following:
(i)    Training of personnel,   and (ii)   Procedures for monitoring
: e. Deleted 5.9-4-f. Primary Containment Leakage Rate Testing Program A program shall be established,    implemented,  and maintained to comply with the leakage rate testing of the containment as required by 10CFR50.54(o) and 10CFR50, Appendix J, Option B. as modified by approved exemptions. Thisprogram shall be in accordance with the guidelines contained in Regulatory Guide 1.163, "Performance-Based Containment Leak-Test ProgramO, dated September 1995, as modified by the following exception:
: a. NZ 94-01-1995, Section 9.2.3: The first Type A test performed after March 24, 1992 shall be performed no later than March 24, 2007.
The punk calculated containment internal pressure for the design basis loss of coolant accident,   P,, is  47.0 psig.
The maximum allowable containment leakage rate, L,. at P4, shall be 0.1%
of primary containment air weight per day.
Leakage Rate Acceptance Criteria are:
: a. Primary containment leakage rate acceptance criterion is less than or equal to 1.0 Ia. During the first unit startup following testing in accordance with this program, the leakage rate SALEM - UNIT 2                         6-19                      Amendment No. 235

acceptance criteria are less than or equal to 0.6 L, for Type B S
and Type C tests and less t.hanf Or equal to 0.75 L. for Type A tests;
: b.      Air lock testing acceptance criteria are:
11Overall air lock leakg',"rate is less than or equal to 0.05..
when tested at greater than or equal to P.,
: 2) Seal leakage rate less than or equal to 0.01 L. per hour when the gap between the door seals is'pressurized to 10.0 psig.
Test frequencies and applicable extensions will be controlled by the Primary Containment Leakage Rate Testing Program.
The provisions of Specification 4.0.3 will be applied to the Primary Containment Leakage Rate Testing Program.
6.8.4.g     Radioactive Effluent Controls Program A program shall be provided conforming with 10 CFR 50.36a for the control of radioactive effluents and for maintaining the doses to the DMER.S OF THE PUBLIC from radioactive effluents as low as reasonably achievable.        The program (11 shall be contained in the ODCK, (2) shall be izplemented by operating procedures, and (3) shall include remedial actions to be taken whenever the program limits are exceeded.       The program shall include the following elements:
: 1) Limitations on the operability of radioactive liquid and gaseous monitoring instrumentation including surveillance tests and setpoint determination in accordance with the methodology in: the OX39,
: 2) Limitations on the concentrations of :adioactive material released in liquid effluents to UNRESTRICTED AREAS conforming co 10 CFR 20, Appendix 3, T'able 11. Columnc 2,
: 3) Monitoring, sampling, and analysis of radioactive liquid and gaseous effluents in accordance with 10 CFR 20.106 and with the methodology and parameters in the ODCM.
: 4) Limitations on the annual and quarterly doses or dose commitment to a MDMSE.OF T1M PUBLIC from radioactive materials in liquid effluents released from each unit to UNRZWRICTED AREAS conforming to Appendix I to 10 CFR Par: 50, 51 Determination of cumulative and projected dose contributions from radioactive effluents for the current calendar quarter and current calendar year in accordance with the methodology and parameters in the OWN! at least every 31 days.
: 6) Limitations on the operability and use of the liquid and gaseous effluent treatment systems to ensure that the appropriate portions of thoese systems are used to reduce releases of radioactivity when the projected doses in a 92-day period would exceed a suitable fraction of the guidelines for the annual dose or dose commitment conforming to Appendix I to 10 CR Part 50, SALEM - UNIT 2                          6-19a                    Amendment No. 215

ADMINISTRATIVE CONTROLS
: 7) Limitations on the dose rate resulting from radioactive material released in gaseous effluents to areas beyond the SITE BOUNDARY conforming to the doses associated with 10 CFR Part 20, Appendix B, Table II,        Column 1,
: 8) Limitations on the annual and quarterly air      doses resulting from noble gases released in gaseous effluents from each unit to areas beyond the SITE BOUNDARY conforming to Appendix I to 10 CFR Part 50,
: 9) Limitations on the annual and quarterly doses to a MEMBER OF THE PUBLIC from Iodine-131, Iodine-133, tritium,      and all  radionuclides in particulate form with half-lives greater than 8 days in gaseous effluents released from each unit to areas beyond the SITE BOUNDARY conforming to Appendix I to 10 CFR Part 50,
: 10)   Limitations on the annual dose or dose commitment to any MEMBER OF THE PUBLIC due to releases of radioactivity and to radiation from uranium fuel cycle sources conforming to 40 CFR Part 190.
6.8.4.h    Radiological Environmental Monitoring Program A program shall be provided to monitor the radiation and radionuclides in the environs of the plant. The program shall provide (1) representative measurements of radioactivity in the highest potential exposure pathways, and (2) verification of the accuracy of the effluent monitoring program and modeling of environmental exposure pathways.        The program shall (1) be contained in the ODCM, (2) conform to the guidance of Appendix I to 10 CFR Part 50, and (3) include the following:
: 1) Monitoring, sampling, analysis,       and reporting of radiation and radionuclides in the environment in      accordance with the methodology and parameters in the ODCM,
: 2)   A Land Use Census to ensure that changes in the use of areas at and beyond the SITE BOUNDARY are identified and that modifications to the monitoring program are made if    required by the results of the census, and
: 3)   Participation in a Interlaboratory Comparison Program to ensure that independent checks on the precision and accuracy of the measurements of radioactive materials in environmental sample matrices are performed as part of the quality assurance program for environmental monitoring.
6.8.4.i    Steam Generator (SG)   Program A Steam Generator Program shall be established and implemented to ensure that SG tube integrity is maintained.       In addition, the Steam Generator Program shall include the following provisions:
SALEM - UNIT 2                            6-19b                     Amendment No. 262

ADMINISTRATIVE CONTROLS
: a. Provisions for condition monitoring assessments.                Condition monitoring assessment means an evaluation of the "as found" condition of the tubing with respect to the performance criteria for structural integrity and accident induced leakage.                  The "as found" condition refers to the condition of the tubing during an SG inspection outage, as determined from the inservice inspection results or by other means, prior to the plugging of tubes.
Condition monitoring assessments shall be conducted during each outage during which the SG tubes are inspected or plugged to confirm that the performance criteria            are being met.
: b. Performance criteria        for SG tube integrity.       SG tube integrity shall be maintained by meeting the performance criteria                 for tube structural integrity,        accident induced leakage, and operational leakage.
: 1. Structural integrity performance criterion:              All in-service steam generator tubes shall retain structural             integrity    over the full      range of normal operating conditions (including startup, operation in the power range, hot standby, and cool down and all       anticipated transients included in the design specification) and design basis accidents.             This includes retaining a safety factor of 3.0 against burst under normal steady state      full power operation primary-to-secondary pressure differential       and a safety factor of 1.4 against burst applied to the design basis accident primary-to-secondary pressure differentials.        Apart from the above requirements, additional loading conditions associated with the design basis accidents, or combination of accidents in accordance with the design and licensing basis, shall also be evaluated to determine if                  the associated loads contribute significantly to burst or collapse.
In the assessment of tube integrity, those loads that do significantly affect burst or collapse shall be determined and assessed in combination with the loads due to pressure with a safety factor of 1.2 on the combined primary loads and 1.0 on axial secondary loads.
: 2. Accident induced leakage performance criterion:                 The primary-to-secondary accident induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all        SGs and leakage rate for an individual SG.
Leakage is not to exceed 1 gallon per minute per SG.
: 3. The operational leakage performance criterion             is    specified in LCO 3.4.7.2, "Reactor Coolant System Operational                Leakage."
: c. Provisions for SG tube repair criteria.              Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40%
of the nominal tube wall thickness shall be plugged.
SALEM - UNIT 2                              6-19c                        Amendment No.      262

ADMINISTRATIVE CONTROLS The following alternate tube repair criteria       may be applied as an alternative to the 40% depth based criteria:
: 1. WEXTEX expanded region inspection methodology (W* Methodology).
This alternate repair criteria   is only applicable to Westinghouse Model 51 SGs with mill annealed Alloy 600 tubing expanded into the tubesheet using the Westinghouse explosive tube expansion (WEXTEX) process. The definitions that apply to W* are provided below:
Bottom of WEXTEX transition (BWT) is the highest point of contact between the tube and the tubesheet at, or below the top-of-tubesheet, as determined by eddy current testing.
W* Length is defined as the length of tubing below the bottom of the WEXTEX transition (BWT) that must be demonstrated to be non-degraded in order for the tube to maintain structural and leakage integrity.       For the hot leg, the W* length is 7.0 inches, which represents the most conservative hot leg length.
W* Distance is defined as the non-degraded distance from the top of the tubesheet to the bottom of the W* length, including the distance from the top-of-tubesheet to the bottom of the WEXTEX transition (BWT) and Non-Destructive Examination (NDE) measurement uncertainties (i.e.,        W*
distance = W* length + distance to BWT + NDE uncertainties). The W* Distance is the larger of the following two distances as measured from the top-of-the-tubesheet (TTS): (a) 8-inches below the TTS or (b) the non-degraded distance from the TTS to the bottom of the W4 length, including the distance from the TTS to the bottom of the WEXTEX transition (BWT) and Non-Destructive Examination (NDE) measurement uncertainties (i.e.,        W*
distance = W* length + distance to BWT + NDE uncertainties)
Tubes within the hot-leg region of the tubesheet with flaws identified in the W* Distance, shall be removed from service on detection by tube plugging. Flaws located below the W*
distance within the hot-leg region of the tubesheet may remain in service regardless of size.
: d. Provisions for SG tube inspections. Periodic SG tube inspections shall be performed. The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., volumetric flaws, axial and circumferential cracks) that may be present along the SALEM - UNIT 2                         6-19d                       Amendment No. 262

ADMINISTRATIVE CONTROLS length of the tube, from the tube-to-tubesheet weld at the tube inlet    to the tube-to-tubesheet weld at the tube outlet, and that may satisfy the applicable tube repair criteria.             The portion of the tube within the hot-leg tubesheet region below the W* distance is excluded.       The tube-to-tubesheet weld is not part of the tube.
In addition to meeting the requirements of d.l,         d.2, d.3, and d.4 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity            is maintained until       the next SG inspection. An assessment of degradation shall be performed to determine the type and location of flaws to which the tubes may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations.
: 1. Inspect 100% of the tubes in each SG during the first refueling outage following SG replacement.
Note:           Step 2 has two separate requirements (a and b),
depending on the type of SG tubes installed.
2a. SGs with Alloy 600 Mill Annealed tubes: Inspect 100% of the tubes at sequential periods of 60 effective full         power months.
The first    sequential period shall be considered to begin after the first   inservice inspection of the SGs. No SG shall operate for more than 24 effective full    power months or one refueling outage (whichever is less) without being inspected.
2b      SGs with Alloy 690 Thermally Treated tubes: Inspect 100% of the tubes at sequential periods of 144, 108, 72, and thereafter, 60 effective full     power months. The first sequential period shall be considered to begin after         the first inservice inspection of the SGs.      In addition, inspect 50% of the tubes by the refueling outage nearest the midpoint of the period and the remaining 50% by the refueling outage nearest the end of the period.      No SG shall operate for more than 72 effective full    power months or three refueling outages (whichever is less) without being inspected.
: 3. If crack indications are found in any SG tube, then the next inspection for each SG for the degradation mechanism that caused the crack indication shall not exceed 24 effective full power months or one refueling outage (whichever is less).             If definitive information, such as from examination of a pulled tube, diagnostic non-destructive testing, or engineering evaluation indicates that a crack-like indication is not associated with a crack(s), then the indication need not be treated as a crack.
SALEM - UNIT 2                            6-19e                    Amendment No.      262

ADMINISTRATIVE CONTROLS
: 4.        When the W* methodology has been implemented, inspect 100 percent of the inservice tubes for the entire hot-leg tubesheet W*
distance with the objective of detecting flaws that may satisfy the applicable tube repair criteria of TS 6.8.4.i.c.1 every 24 effective full power months or one refueling outage (whichever is less).
: e.       Provisions for monitoring operational primary-to-secondary leakage, 6.8.4.j      Inservice Testing Program This Program provides controls for inservice testing of ASME Code Class 1, 2, and 3 components. The program shall include the following:
: a.       Testing frequencies applicable to the ASME Code for Operations and Maintenance of Nuclear Power Plants (ASME OM Code) and applicable Addenda as follows:
ASME OM Code and applicable              Required Frequencies for Addenda terminology for                  performing inservice inservice testing activities             testing activities Weekly                                   At least once per 7 days Monthly                                  At least once per 31 days Quarterly or every 3 months              At least once per 92 days Semiannually or every 6 months           At least once per 184 days Every 9 months                           At least once per 276 days Yearly or annually                       At least once per 366 days Biennially or every 2 years             At least once per 731 days
: b.       The provisions of Specification 4.0.2 are applicable to the above required frequencies and to other normal and accelerated frequencies specified as 2 years or less in the Inservice Testing Program for performing inservice testing activities,
: c.       The provisions of Specification 4.0.3 are applicable to inservice testing activities, and
: d.        Nothing in the ASME OM Code shall be construed to supersede the requirements of any Technical Specification.
6.8.4,k      Reactor Coolant Pump Flywheel Inspection Proqram In addition to the requirements of the ISI Program, each Reactor Coolant Pump flywheel shall be inspected per the recommendations of Regulatory Position C.4.b of Regulatory Guide 1.14, Revision 1, August 1975, In lieu of Position C.4.b(1) and C.4.b(2), a qualified in-place UT examination over the volume from the inner bore of the flywheel to the circle one-half of the outer radius or a surface examination (MT and/or PT) of exposed surfaces of the removed flywheels may be conducted at 20 year intervals.
SALEM - UNIT 2                                 6-1 9f                            Amendment No. 281

ADMINISTRATIVE CONTROLS 6.8.4.1     Surveillance Frequency Control Program This program provides controls for Surveillance Frequencies. The program shall ensure that Surveillance Requirements specified in the Technical Specifications are performed at intervals sufficient to assure the associated Limiting Conditions for Operation are met.
: a.      The Surveillance Frequency Control Program shall contain a list of Frequencies of those Surveillance Requirements for which the Frequency is controlled by the program.
: b.      Changes to the Frequencies listed in the Surveillance Frequency Control Program shall be made in accordance with NEI 04-10, "Risk-Informed Method for Control of Surveillance Frequencies," Revision 1.
: c.      The provisions of Surveillance Requirements 4.0.2 and 4.0.3 are applicable to the Frequencies established in the Surveillance Frequency Control Program.
6.8.4.m     Snubber Testinq Program This program conforms to the examination, testing and service life monitoring for dynamic restraints (snubbers) in accordance with 10 CFR 50.55a inservice inspection (ISI) requirements for supports. The program shall be in accordance with the following:
(i)     This program shall meet 10 CFR 50.55a(g) ISI requirements for supports.
(ii)    The program shall meet the requirements for ISI of supports set forth in subsequent editions of the Code of Record and addenda of the American Society of Mechanical Engineers (ASME) Boiler and Pressure (BPV)
Code and the ASME Code for Operation and Maintenance of Nuclear Power Plants (OM Code) that are incorporated by reference in 10 CFR 50.55a(b) subject to limitations and modifications listed in 10 CFR 50.55a(b) and subject to Commission approval.
(iii)   The program shall, as allowed by 10 CFR 50.55a(b)(3)(v), meet Subsection ISTA, "General Requirements" and Subsection ISTD, "Preservice and Inservice Examination and Testing of Dynamic Restraints (Snubbers) in Light-Water Reactor Nuclear Power Plants" in lieu of Section XI of the ASME BPV Code ISI requirements for snubbers, or meet authorized alternatives pursuant to 10 CFR 50.55a(a)(3).
(iv)   The 120-month program updates shall be made in accordance with 10 CFR 50.55a (including 10 CFR 50.55a(b)(3)(v)) subject to the limitations and modifications listed therein.
SALEM - UNIT 2                              6-19g                          Amendment No. 284

ADMINISTRATIVE               CONTROLS wmnngmnmummmsmlmmllIiiiiliimauawmwmulinuuinmuinumlIumiiuin.in...mi*n..
6.9     REPORTING            REOUTREMINTS ROUTgILN      REPORTS 6.9.1       In addition to the applicable reporting requirements of Title 10,                      Code of Federal       Regulations, the following reports shall be submitted to the U.S.
Nuclear Regulatory Comuission, Document Control Desk, Washington, D.C. 20555, with a copy to the USNRC Administrator, Region I, unless otherwise noted.
STARTUP REPORT 6.9.1.1        A summary report of plant startup and power escalation testing shall be submitted following (1) receipt of an operating license, (2) amendment to the license Involving a planned increase in power level, (3) installation                           of fuel that       has different design or has been manufactured by a different fuel supplier, and (4) modifications that may have significantly altered the nuclear, thermal, or hydraulic performance of the plant.
6.9.1.2        The startup report shall address each of the tests                     identified in the tSAR and shall include a description of measured values of the operating conditions or characteristics obtained during the test                          program and a comparison of these values with design predictions and specifications.                            Any corrective actions that were required to obtain satisfactory operation shall also be described.                  Any additional specific details          required in license conditions based on other commitments shall be included in this                           report.
6.9.1.3        Startup reports shall be submitted within (1) 90 days following completion of the startup test program, (2) 90 days following resumption or commencement of commercial power operation, or (3) 9 months following initial criticality, whichever is earliest. If the Startup Report does not cover all three events (i.e., initial criticality, completion of startup test program, and resumption or commencement of commercial power operation), supplementary reports shall be submitted at least every three months until all three events have been completed.
ANNUM.. REPORTS'*
6.9.1.4 Annual reports covering the activities of the unit as described below for the previous calendar year shall be submitted prior to March I of each year.
A single submittal may be made for a multiple unit station. The submittal should combine those sections that are common to all units at the station.
SALEM     -  UNIT 2                                                     6-20          Amendment No. 112

ADMINISTRATIVE CONTROLS 6.9.1.5 Reports required on an annual basis shall include:
: a. DELETED
: b. DELETED
: c. The results of any specific activity analyses in which the primary coolant exceeded the limits of Specification 3.4.9. The following information shall be included: (1) Reactor power history starting 48 hours prior to the first sample in which the limit was exceeded; (2) Results of the last isotopic analysis for radioiodine performed prior to exceeding the limit, results of analysis while the limit was exceeded and results of one analysis after the radioiodine activity was reduced to less than the limit. Each result should include date and time of sampling and the radioiodine concentrations; (3) Clean-up system flow history starting 48 hours prior to the first sample in which the limit was exceeded; (4) Graph of the 1-131 concentration and one other radioiodine isotope concentration in microcuries per gram as a function of time for the duration of the specific activity above the steady state level; and (5) The time duration when the specific activity of the primary coolant exceeded the radioiodine limit.
MONTHLY OPERATING REPORT 6.9.1.6 DELETED SALEM - UNIT 2                                  6-21                          Amendment No. 278

ADMINISTRATIVE CONTROLS ANNUAL RADIOLOGICAL ENVIRONMENTAL OPERATING REPORT*
6.9.1.7 The Annual Radiological Environmental Operating Report covering the operation of the unit during the previous calendar year shall be submitted before May 1 of each year. The report shall include summaries, interpretations, and analysis of trends of the results of the Radiological Environmental Monitoring Program for the reporting period. The material provided shall be consistent with the objectives outlined in (1) the ODCM and (2) Sections IV.B.2, IV.B.3, and IV.C of Appendix I to 10 CFR 50.
ANNUAL RADIOACTIVE EFFLUENT RELEASE REPORT*
6.9.1.8 The Annual Radioactive Effluent Release Report covering the operation of the unit during the previous 12 months of operation shall be submitted before May 1 of each year. The report shall include a summary of the quantities of radioactive liquid and gaseous effluents and solid waste released from the unit. The material provided shall be (1) consistent with the objective outlined in the ODCM and PCP and (2) in conformance with 10 CFR 50.36a and Section IV.B.l of Appendix I to 10 CFR 50.
A single submittal may be made for a multiple unit station. The submittal should combine those sections that are common to all units at the station; however, for units with separate radwaste systems, the submittal shall specify the releases of radioactive material from each unit.
SALEM - UNIT 2                       6-22                    Amendment No. 215 6

This Page Intentionally Blank SALEM - UNIT 2            6-23               Amendment No. 215

ADMINISTRATIVE CONTROLS 6.9.1.9 CORE OPERATING LIMITS REPORT (COLR)
: a. Core operating limits shall be established prior to each reload cycle, or prior to any remaining portion of a reload cycle, and shall be documented in the COLR for the following:
: 1.       Moderator Temperature Coefficient Beginning of Life (BOL) and End of Life (EOL) limits and 300 ppm surveillance limit for Specification 3/4.1.1.3,
: 2.        Control Bank Insertion Limits for Specification 3/4.1.3.5,
: 3.       Axial Flux Difference Limits and target band for Specification 3/4.2.1,
: 4.        Heat Flux Hot Channel Factor, FQ, its variation with core height, K(7), and Power Factor Multiplier PFy, Specification 3/4.2.2, and
: 5.       Nuclear Enthalpy Hot Channel Factor, and Power Factor Multiplier, PF&H for Specification 3/4.2.3.
: 6.       Refueling boron concentration per Specification 3.9.1
: b. The analytical methods used to determine the core operating limits shall be those previously reviewed and approved by the NRC, specifically those described in the following documents:
: 1.       WCAP-9272-P-A, WestinQhouse Reload Safety Evaluation Methodology,
(_W Proprietary), Methodology for Specifications listed in 6.9.1.9.a.
SALEM - UNIT 2                                   6-24                          Amendment No. 278

ADMINISTRATIVE CONTROLS
: 2.      WCAP-8385, Power Distribution Control and Load Following Procedures -
Topical Report, (WProprietary) Methodology for Specification 3/4.2.1 Axial Flux Difference
: 3.      WCAP-10054-P-A, Westinghouse Small Break ECCS Evaluation Model Using NOTRUMP Code, (W Proprietary), Methodology for Specification   3/4.2.2 Heat Flux Hot Channel Factor.
: 4.      WCAP-10266-P-A, The 1981 Version of Westinghouse Evaluation Model Using BASH Code, (W Proprietary) Methodology for Specification 3/4.2.2 Heat Flux Hot Channel Factor.
: 5.      WCAP-12472-P-A, BEACON - Core Monitoring and Operations Support System, ( W Proprietary).
: 6. CENPD-397-P-A, Improved Flow Measurement Accuracy Using Crossflow Ultrasonic Flow Measurement Technology
: 7. WCAP-10054-P-A, Addendum 2, "Addendum to the Westinghouse Small Break ECCS Evaluation Model Using the NOTRUMP Code:     Safety Injection into the Broken Loop and COSI Condensation Model."
: c. The core operating limits shall be determined such that all applicable limits (e.g., fuel thermal mechanical limits, core thermal hydraulic limits, Emergency Core Cooling Systems (ECCS) limits, nuclear limits such as SDM, transient analysis limits, and accident analysis limits) of the safety analysis are met.
: d. The COLR, including any mid-cycle revisions or supplements shall be provided upon issuance for each reload cycle to the NRC.
6.9.1.10     STEAM GENERATOR TUBE INSPECTION REPORT A report shall be submitted within 180 days after the initial        entry into HOT SHUTDOWN following completion of an inspection performed in accordance with the Specification 6.8.4.i, "Steam Generator (SG) Program."       The report shall include:
: a. The scope of inspections performed on each SG,
: b. Active degradation mechanisms found,
: c. Nondestructive examination techniques utilized for each degradation mechanism,
: d. Location, orientation (if linear),     and measured sizes (if  available) of service induced indications, SALEM - UNIT 2                          6-24a                    Amendment No. 267

ADMINISTRATIVE CONTROLS
: e.      Number of tubes plugged during the inspection outage for each active degradation mechanism,
: f.      Total number and percentage of tubes plugged to date,
: g.      The results of condition monitoring,  including the results of tube pulls and in-situ testing.
: h.      Information regarding the application of W* inspection methodology (applicable to tubes within the hot-leg region of the tubesheet); including the number of indications, the location of indications (relative to the BWT and TTS), the orientation (axial, circumferential, volumetric), the severity of each indication (e.g., near through-wall or not through wall),
the tube side where the indication initiated (inside or outside diameter),
the cumulative number of indications detected in the tubesheet region as a function of elevation within the tubesheet, the condition monitoring and operational assessment main steam line leak rate (including aggregate calculated main steam line break leak rate from all other sources), and an assessment of whether the results were consistent with expectations regarding the number of flaws and flaw severity (and if not consistent, a description of the proposed corrective action).
SPECIAL REPORTS 6.9.2r Special reports shall be submitted to the U.S. Nuclear Regulatory Commission, Document Control Desk, Washington, D.C. 20555, with a copy to the Administrator, USNRC Region I within the time period specified for each report.
6.9.3,DELETED 6.9.4 When a report is required by ACTION 8 OR 9 of Table 3.3-11 "Accident Monitoring Instrumentation", a report shall be submitted within the following 14 days. The report shall outline the preplanned alternate method of monitoring for inadequate core cooling, the cause of the inoperability, and the plans and schedule for restoring the instrument channels to OPERABLE status.
SALEM - UNIT-2                         6-24b                    Amendment No. 275

ADMINISTRATIVE CONTROLS 6.10    RECORD RETENTION In addition to the applicable record retention requirements of Title 10, Code of Federal Regulations, the following records shall be retained for at least the minimum period indicated.
6.10.1    The following records shall be retained for at least five years:
a,    Records and logs of unit operation covering time interval at each power level.
: b. Records and logs of principal maintenance activities, inspections, repair and replacement of principal items of equipment related to nuclear safety,
: c. All REPOF <ABLE EVENTS submitted to the Commission.
: d. Records of surveillance activities, inspections and calibrations required by these Technical Specifications.
: e. DELETED
: f. Records of changes made to Operating Procedures required by Specification 6.8.1.
: g. Records of radioactive shipments.
: h. Records of sealed source and fission detector leak tests and results.
: i. Records of annual physical inventory of all sealed source material of record.
: j. Records of reviews performed for changes made to procedures or reviews of tests and experiments, pursuant to 10CFR50.59, 6.10.2 The following records shall be retained for the duration of the Unit Operating License:
: a. Records and drawing changes reflecting unit design modifications made to systems and equipment described in the Final Safety Analysis Report, pursuant to 10CFR50.59.
: b. Records of new and irradiated fuel inventory, fuel transfers and assembly burnup histories.
SALEM - UNIT 2                         6-25                    Amendment No. 117

ADMINISTRATIVE CONTROLS
: c. Records of radiation exposure for all individuals entering radiation control areas.
: d. Records of gaseous and liquid radioactive material released to the environs.
: e. Records of transient or operational cycles for those facility components identified in Table 5.7-1.
: f.      Records of reactor tests and experiments.
: g.      Records of training and qualification for current members of the plant staff.
: h. Records of in-service inspections.
: i. Records of Quality Assurance activities required by the QA Manual.
: j.      DELETED
: k. Records of SORC meetings and activities of the Nuclear Review Board (and activities of its predecessor, the Offsite Safety Review (OSR) staff).
: 1. Records for Environmental Qualification which are covered under the provisions of Paragraph 2.C(7) and 2,C(8) of Facility Operating License DPR-75.
: m. Records of the service lives of all hydraulic and mechanical snubbers including the date at which the service life commences and associated installation and maintenance records.
: n. Records of secondary water sampling and water quality.
: o. Records of analyses required by the radiological environmental monitoring program which would permit evaluation of the accuracy of the analysis at a later date. This should include procedures effective at specified times and QA records showing that these procedures were followed.
: p. Records of reviews performed for changes made to the OFFSITE DOSE CALCULATION MANUAL and the PROCESS CONTROL PROGRAM.
6.11 RADIATION PROTECTION PROGRAM Procedures for personnel radiation protection shall be prepared consistent with the requirements of 10 CFR Part 20 and shall be approved, maintained and adhered to for all operations involving personnel radiation exposure.
SALEM - UNIT 2                                   6-26                         Amendment No. 279

ADMINISTRATIVE CONTROLS 6.12 HIGH RADIATION AREA As provided in paragraph 20.1601(c) of 10 CFR Part 20, the following controls shall be applied to high radiation areas in place of the controls required by paragraph.20.1601(a) and (b) of 10 CFR Part 20:
6.12.1       High Radiation Areas with Dose Rates Not Exceeding 1.0 rem/hour at 30 Centimeters from the Radiation Source or from any Surface Penetrated by the Radiation
: a. Each entryway to such an area shall be barricaded and conspicuously posted as a high radiation area. Such barricades may be opened as necessary to permit entry or exit of personnel or equipment.
: b. Access to, and activities in, each such area shall be controlled by means of Radiation Work Permit (RWP) or equivalent that includes specification of radiation dose rates in the immediate work area(s) and other appropriate radiation protection equipment and measures.
C. Individuals qualified in radiation protection procedures and personnel continuously escorted by such individuals may be exempted from the requirement for an RWP or equivalent while performing their assigned duties provided that they are otherwise following plant radiation protection procedures for entry to, exit from, and work in such areas.
: d. Each individual or group entering such an area shall possess:
: 1. A radiation monitoring device that continuously displays radiation dose rates in the area; or
: 2. A radiation monitoring device that continuously integrates the radiation dose rates in the area and alarms when the device's dose alarm setpoint is reached, with an appropriate alarm setpoint, or
: 3. A radiation monitoring device that continuously transmits dose rate and cumulative dose information to a remote receiver monitored by radiation protection personnel responsible for controlling personnel radiation exposure within the area, or
: 4. A self-reading dosimeter (e.g., pocket ionization chamber or electronic dosimeter) and, (i)   Be under the surveillance, as specified in the RWP or equivalent, while in the area, of an individual qualified in radiation protection procedures, equipped with a radiation monitoring device that continuously displays radiation dose rates in the area; who is responsible for controlling personnel exposure within the area, or SALEM - UNIT 2                         6-27                      Amendment No. 236

(ii)  Be under the surveillance as specified in the RWP or equivalent, while in the area, by means of closed circuit television, of personnel qualified in radiation protection procedures, responsible for controlling personnel radiation exposure in the area, and with the means to communicate with individuals in the area who are covered by such surveillance.
: e. Except for individuals qualified in radiation protection procedures, or personnel continuously escorted by such individuals, entry into such areas shall be made only after dose rates in the area have been determined and entry personnel are knowledgeable of them. These continuously escorted personnel will receive a pre-job briefing prior to entry into such areas. This dose rate determination, knowledge, and pre-job briefing does not require documentation prior to initial entry.
6.12.2       High Radiation Areas with Dose Rates Greater than 1.0 rem/hour at 30 Centimeters from the Radiation Source or from any Surface Penetrated by the Radiation, but less than 500 rads/hour at 1 Meter from the Radiation Source or from any Surface Penetrated by the Radiation
: a. Each entryway to such an area shall be conspicuously posted as a high radiation area and shall be provided with a locked or continuously guarded door or gate that prevents unauthorized entry, and, in addition:
: 1. All such door and gate keys shall be maintained under the administrative control of the shift supervisor, radiation protection manager, or his or her designee.
: 2. Doors and gates shall remain locked except during periods of personnel or equipment entry or exit.
: b. Access to, and activities in, each such area shall be controlled by means of an RWP or equivalent that includes specification of radiation dose rates in the immediate work area(s) and other appropriate radiation protection equipment and measures.
: c. Individuals qualified in radiation protection procedures may be exempted from the requirement for an RWP or equivalent while performing radiation surveys in such areas provided that they are otherwise following plant radiation protection procedures for entry to, exit from, and work in such areas.
: d. Each individual or group entering such an area shall possess:
: 1. A radiation monitoring device that continuously integrates the radiation dose rates in the area and alarms when the device's dose alarm setpoint is reached, with an appropriate alarm setpoint, or SALEM  - UNIT 2                        6-27a                      Amendment No. 236
: 2. A radiation monitoring device that continuously transmits dose rate and cumulative dose information to a remote receiver monitored by radiation protection personnel responsible for controlling personnel radiation exposure within the area with the means to communicate with and control every individual in the area, or
: 3. A self-reading dosimeter (e.g., pocket ionization chamber or electronic dosimeter) and, (i)    Be under the surveillance, as specified in the RWP or equivalent, while in the area, of an individual qualified in radiation protection procedures, equipped with a radiation monitoring device that continuously displays radiation dose rates in the area; who is responsible for controlling personnel exposure within the area, or (ii)  Be under the surveillance as specified in the RWP or equivalent, while in the area, by means of closed circuit television, of personnel qualified in radiation protection procedures, responsible for controlling personnel radiation exposure in the area, and with the means to communicate with and control every individual in the area.
: 4. In those cases where options (2) and (3), above, are impractical or determined to be inconsistent with the "As Low As is Reasonably Achievable' principle, a radiation monitoring device that continuously displays radiation dose rates in the area.
: e. Except for individuals qualified in radiation protection procedures, or personnel continuously escorted by such individuals, entry into such areas shall be made only after dose rates in the area have been determined and entry personnel are knowledgeable of them. These continuously escorted personnel will receive a pre-job briefing prior to entry into such areas. This dose rate determination, knowledge, and pre-job briefing does not require documentation prior to initial entry.
: f. Such individual areas that are within a larger area where no enclosure exists for the purpose of locking and where no enclosure can reasonably be constructed around the individual area need not be controlled by a locked door or gate, nor continuously guarded, but shall be barricaded, conspicuously posted, and a clearly visible flashing light shall be activated at the area as a warning device.
SALEM - UNIT 2                      6-27b                     Amendment No. 235

D 6.13   PROCESS CONTROL PROGRAM   (PCP) 6.13.1   The PCP shall be approved by the Commission prior to implementation.
6.13.2   Changes to the PCP:
: 1. Shall be documented and records of review performed shall be retained as required by Specification 6.20.3p. This documentation shall contain:
a) Sufficient information to support the change together with the appropriate analyses or evaluations justifying the change(s) and b) A determination that the change will maintain the overall conformance of the solidified waste product to existing requirements of Federal, State, or other applicable regulations.
: 2. Shall become effective after review and acceptance by the SORC and the approval of the Plant Manager.
6 SALEM -  UNIT 2                        6-28                    Amendment No. 236 I
E

ADMINISTRATIVE CONTROLS 6.14   OFFSITE DOSE CALCULATION MANUAL (ODCM) 6.14.1    The ODCM shall be approved by the Commission prior to implementation.
6.14.2    Changes to the ODCM:
: 1. Shall be documented and records of reviews performed shall be retained as required by Specification 6.10.3p. This documentation shall contain:
a) Sufficient information to support the change together with the appropriate analyses or evaluations justifying the change(s) and b) A determination that the change will maintain the level of radioactive effluent control required by 10 CFR 20.106, 40 CFR Part 190, .10 CFR 50.36a, and Appendix I to 10 CFR Part 50 and not adversely impact the accuracy or reliability of effluent, dose, or setpoint calculations.
: 2. Shall become effective after review and acceptance by the SORC and the approval of the Plant Manager.
: 3. Shall be submitted to the Commission in the form of a complete, legible copy of the entire ODCM as a part of or concurrent with the Annual Radioactive Effluent Release Report for the period of the report in which any change to the ODCM was made. Each change shall be identified by markings in the margin of the affected pages, clearly indicating the area of the page that was changed, and shall indicate the date (e.g. month/year) the change was implemented.
6.15   MAJOR CHANGES TO RADIOACTIVE LIQUID, GASEOUS AND SOLID WASTE TREATMENT SYSTEMS 6.15.1 Licensee initiated major changes to the radioactive waste system (liquid, gaseous and solid):
I.      Shall be reported to the Commission in the UFSAR for the period in which the evaluation was reviewed by (SORC). The discussion of each change shall contain:
: a. A summary of the evaluation that led td the determination that the change could be made in accordance with 10CFR50.59;
: b. Sufficient detailed information to totally support the reason for the change without benefit of additional or supplemental information; SALEM - UNIT 2                           6-29                   Amendment No. 215
: c. A detailed description of the equipment, components and processes involved and the interfaces with other plant systems;
: d. An evaluation of the change, which shows the predicted releases of radioactive materials in liquid and gaseous effluents and/or quantity of solid waste that differ from those previously predicted in the license application and amendments thereto;
: e. An evaluation of the change, which shows the expected maximum exposures to individual in the unrestricted area and to the general population that differ from those previously estimated in the license application and amendments thereto;
: f. A comparison of the predicted releases of radioactive materials, in liquid and gaseous effluents and in solid waste, to the actual releases for the period prior to when the changes are to be made;
: g. An estimate of the exposure to plant operating personnel as a result of the change; and
: h. Documentation of the fact that the change was reviewed and found acceptable by the (SORC).
: 2. Shall become effective upon review and acceptance by the SORC.
6.16 TECHNICAL SPECIFICATION    (TS) BASES CONTROL PROGRAM This program provides a means ifor processing changes to the Bases of these Technical Specifications.
: a. Changes to the Bases of the TS shall be made under appropriate administrative controls and reviews.
: b. PSEG may make changes to the Bases without prior NRC approval provided the changes do not require either of the following:
: 1. A change in  the TS incorporated in  the License, or
: 2. A change to the updated FSAR or Bases that requires NRC approval pursuant to 10 CFR 50.59.
: c. Proposed changes to the Bases that require either condition of Specification 6.16.b above shall be reviewed and approved by the NRC prior to implementation.
: d. Changes to the Bases implemented without prior NRC approval shall be provided to the NRC on a frequency consistent with 10 CFR 50.71(e).
: e. The Bases Control Program shall contain provisions to ensure that the Bases are maintained consistent with the UFSAR.
II SALEM - UNIT 2                         6-30                     Amendment No. 237

ADMINISTRATIVE CONTROLS 6.17  CONTROL ROOM ENVELOPE HABITABILITY    PROGRAM A Control Room Envelope (CRE) Habitability Program shall be established and implemented to ensure that CRE habitability is maintained such that, with an OPERABLE Control Room Emergency Air Conditioning System (CREACS),     CRE occupants can control the reactor safely under normal conditions and maintain it in a safe conditi~on following a radiological event, hazardous chemical release, or a smoke challenge. The program shall ensure that adequate radiation protection is provided to permit access and occupancy of the CRE under design basis accident (DBA) conditions without personnel receiving radiation exposures in excess of 5 rem total    effective dose equivalent (TEDE) for the duration of the accident. The program shall include the following elements:
: a.      The definition of the CRE and the CRE boundary.
: b.      Requirements for maintaining the CRE boundary in its design condition including configuration control and preventive maintenance.
: c.      Requirements for (i) determining the unfiltered air inleakage past the CRE boundary into the CRE in accordance with the testing methods and at the
        'Frequencies specified in Sections C.1 and C.2 of Regulatory Guide 1.197,
         '!Demonstrating Control Room Envelope Integrity at Nuclear Power Reactors,"
Revision 0, May 2003, and (ii)   assessing CRE habitability at the Frequencies specified in Sections C.1 and C.2 of Regulatory Guide 1.197, Revision 0.
: d. Measurement, at designated locations, of the CRE pressure relative to all external areas adjacent to the CRE boundary during the pressurization mode of operation by one train of the CREACS, operating at the flow rate required by the Surveillance Requirements, at a frequency of 36 months on a STAGGERED TEST BASIS. The results shall be trended and used as part of the 18 month assessment of the CRE boundary.
: e.      The quantitative limits on unfiltered air inleakage into the CRE. These limits shall be stated in a manner to allow direct comparison to the unfiltered air inleakage measured by the testing described in paragraph c.
:The unfiltered air inleakage limit for radiological challenges is the
         &#xfd;nleakage flow rate assumed in the licensing basis analyses of DBA consequences. Unfiltered air inleakage limits for hazardous chemicals must ensure that exposure of CRE occupants to these hazards will be within the assumptions in the licensing basis.
: f.      The provisions of Surveillance Requirement 4.0.2 are applicable to the Frequencies for assessing CRE habitability, determining CRE unfiltered inleakage, and measuring CRE pressure and assessing the CRE boundary as required by paragraphs c and d, respectively.
SALEM - UNIT 2                                                 Amendment No. 269

3/4:.0 APPLICABILITY LIMITING CONDITION FOR OPERATION 3.0.1       Compliance with the limiting Conditions for Operation contained in    the succeeding specifications is required during the OPERATIONAL MODES or other conditions specified therein; except that upon failure to meet the Limiting Conditions for Operation, the associated ACTION requirements shall be met.
3.0.2       Noncompliance with a specification shall exist when the requirements of the Limiting Condition for Operation and associated ACTION requirements are not met within the specified time intervals.       If the Limiting Condition for Operation is restored prior to expiration of the specified time intervals, completion of the ACTION requirements is not required.
3.0.3       When a Limiting Condition for Operation is not met except as provided in the associated ACTION requirements, within one hour action shall be initiated to place the unit in a MODE in which the specification does not apply by placing it,    as applicable, in:
: 1. At leasnt HOT STANDBY within the next 6 hours,
: 2. At least HOT SHUTDOWN within the following 6 hours,    and
: 3. At least COLD SHUTDOWN within the subsequent 24 hours.
Where corrective measures are completed that permit operation under the ACTION requirements, the ACTION may be taken in accordance with the specified time limits as measured from the time of failure to meet the Limiting Condition for Operation. Exceptions to these requirements are stated in the individual specifications.
3.0.4 When an LCO is not met, entry into a MODE or other specified condition in the Applicability shall only be made:
: a. When the associated ACTIONS to be entered permit continued operation in the MODE or other specified condition in the Applicability for an unlimited period of time; or
: b. After performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering the MODE or other specified condition in the Applicability, and establishment of risk management actions, if appropriate; exceptions to this Specification are stated in the individual Specifications, or
: c. When an allowance is   stated in the individual value,  parameter, or other Specification.
This Specification shall not prevent changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit.
SALEM - UNIT 2                          3/4 0-1             Amendment No. 258

APPLICABILITY LIMITING CONDITION FOR OPERATION 3.0.5   DELETED 3.0.6 Equipment removed from service or declared inoperable to comply with ACTIONS may be returned to service under administrative control solely to perform testing required to demonstrate its OPERABILITY or the OPERABILITY of other equipment. This is an exception to LCO 3.0.2 for the system returned to service under administrative control to perform the testing required to demonstrate OPERABILITY.
UTfl~T SALEM    2                   34/A 0-2                     " NT%  01A   0

APPLICABILITY SURVEILLANCE REQUIREMENTS 4.0.1 Surveillance Requirements shall be met during the OPERATIONAL MODES or other specified conditions in the Applicability for individual Limiting Conditions for Operation, unless otherwise stated in the Surveillance Requirement. Failure to meet a Surveillance, whether such failure is experienced during the performance of the Surveillance or between performances of the Surveillance, shall be failure to meet the Limiting Condition for Operation. Failure to perform a Surveillance within the specified frequency shall be failure to meet the Limiting Condition for Operation, except as provided in Specification 4.0.3. Surveillances do not have to be performed on inoperable equipment or variables outside specified limits.
4.0.2 Each Surveillance Requirement shall be performed within the specified surveillance interval with a maximum allowable extension not to exceed 25 percent of the specified surveillance interval.
4.0.3 If it is discovered that a Surveillance was not performed within its specified frequency, then compliance with the requirement to declare the Limiting Condition for Operation not met may be delayed, from the time of discovery, up to 24 hours or up to the limit of the specified frequency, whichever is greater. This delay period is permitted to allow performance of the Surveillance. A risk evaluation shall be performed for any Surveillance .delayed greater than 24 hours and the risk impact shall be managed.
If the Surveillance is not performed within the delay period, the Limiting Condition for Operation must immediately be declarednot met and the applicable Actions must be entered.
When the Surveillance is performed within the delay period and the Surveillance is not met, the Limiting Condition for Operation must immediately be declared not met and the applicable Actions must be entered.
4.0.4 Entry into a MODE or other specified condition in the Applicability of an LCO shall only be made when the LCO's Surveillances have been met within their specified Frequency, except as provided by SR 4.0.3. When an LCO is not met due to Surveillances not having been met, entry into a MODE or other specified condition in the Applicability shall only be made in accordance with LCO 3.0.4.
This provision shall not prevent entry into MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit.
SALEM - UNIT 2                                  3/4 0-3                          Amendment No. 279

3/4.1 REACTIVITY CONTROL SYSTEMS 3/4.1.1 BORATION CONTROL SHUTDOWN MARGIN - Tav_> 200&deg;F LIMITING CONDITION FOR OPERATION 3.1.1.1 The SHUTDOWN MARGIN shall be greater than or equal to 1.3% delta k/k.
APPLICABILITY: MODES 1, 2*, 3, and 4.
ACTION:
With the SHUTDOWN MARGIN less than 1.3% delta k/k, immediately initiate and continue boration at > 33 gpm of a solution containing > 6,560 ppm boron or equivalent until the required SHUTDOWN MARGIN is restored.
SURVEILLANCE REQUIREMENTS 4.1.1.1.1 The SHUTDOWN MARGIN shall be determined to be greater than or equal to 1.3%
delta k/k:
: a. Within 1 hour after detection of an inoperable control rod(s) and at least once per 12 hours thereafter while the rod(s) is inoperable. If the inoperable control rod is immovable or untrippable, the above required SHUTDOWN MARGIN shall be increased by an amount at least equal to the withdrawn worth of the immovable or untrippable control rod(s).
: b. When in MODE 1 or MODE 2 with Keff greater than or equal to 1.0, in accordance with the Surveillance Frequency Control Program by verifying that control banks are within the limits in the COLR per Specification 3.1.3.5.
: c. When in MODE 2 with Ke, less than 1.0, within 4 hours prior to achieving reactor criticality by verifying that the predicted critical control rod position is within the limits in the COLR per Specification 3.1.3.5.
*See Special Test Exception 3.10.1 SALEM - UNIT 2                                   3/4 1-1                          Amendment No. 282

REACTIVITY CONTROL SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)
: d.      Prior to initial operation above 5% RATED THERMAL POWER after each fuel loading, by consideration of the factors of e below, with the control banks at the maximum insertion limit in the COLR per Specification 3.1.3.5.
: e.      When in MODES 3 or 4, in accordance with the Surveillance Frequency Control Program by consideration of the following factors:
: 1.       Reactor coolant system boron concentration,
: 2.       Control rod position,
: 3.       Reactor coolant system average temperature,
: 4.       Fuel burnup based on gross thermal energy generation,
: 5.      Xenon concentration, and
: 6.       Samarium concentration.
4.1.1.1.2 The overall core reactivity balance shall be compared to predicted values to demonstrate agreement within +/- 1% delta k/k in accordance with the Surveillance Frequency Control Program. This comparison shall consider at least those factors stated in Specification 4.1.1.1.1.e, above. The predicted reactivity values shall be adjusted (normalized) to correspond to the actual core conditions prior to exceeding a fuel burnup of 60 Effective Full Power Days after each fuel loading.
SALEM - UNIT 2                                  3/4 1-2                        Amendment No. 282

REACTIVITY CONTROL SYSTEMS SHUTDOWN MARGIN - T,,,-.<20 0 &deg;F LIMITIG CONDITION FOR OPERATION 3.1.1.2 The SHUTDOWN MARGIN shall be greater than or equal to 1.0% delta klk.
APPLICABILITY: MODE 5.
ACTION:
With the SHUTDOWN MARGIN less than 1.0% delta k/k, immediately initiate and continue boration at > 33 gpm of a solution containing _>6,560 ppm boron or equivalent until the required SHUTDOWN MARGIN is restored.
SURVEILLANCE REQUIREMENTS 4.1.1.2 The SHUTDOWN MARGIN shall be determined to be greater than or equal to 1.0%
delta k/k:
: a. Within 1 hour after detection of an inoperable control rod(s) and at least once per 12 hours thereafter while the rod(s) is inoperable. If the inoperable control rod is immovable or untrippable, the SHUTDOWN MARGIN shall be increased by an amount at least equal to the withdrawn worth of the immovable or untrippable control rod(s).
: b. In accordance with the Surveillance Frequency Control Program by consideration of the following factors:
: 1.      Reactor coolant system boron concentration,
: 2.      Control rod position,
: 3.      Reactor coolant system average temperature,
: 4.      Fuel burnup based on gross thermal energy generation,
: 5.      Xenon concentration, and
: 6.      Samarium concentration.
SALEM - UNIT 2                                3/4 1-3                         Amendment No. 282

RZACTIVITY CONTROL SYSTEMS MODEMATOR TE    RATERZ COErFICIENT LIMITING CONDITION FOR OPERATION 3.1.1.3 The moderator temperature coefficient (1,C) shall be within the limits specified i1 the CORE OPERATING LIMITS REPORT (COLR). The maximum upper limit shall be less positive than or equal to 0 Ak/k/*F.
AppLZIARILT: Beginning of Cycle Life (SOL) Limit - bC=ZS I and 2* only#
End of Cycle Life (EOL) Limit - MMDES 1, 2 and 3 only#              I
: a. With the MTC more positive than the BOL limit specified in   the COLR, operations in MODES 1 and 2 may proceed provided:
: 1. Control rod withdrawal limits are established and maintained sufficient to restore the MTC to less positive than the SOL limit specified in the COLR within 24 hours or be in HOT STANDBY within the next 6 hours. These withdrawal limits shall be in addition to the insertion limits in the COLR per Specification 3.1.3.5.
: 2. The control rods are maintained within the withdrawal     mliits  -
established above until a subsequent calculation verifies that the MTC has been restored to within its limit for the all rods wi thdrawn condition.
: 3. In lieu of any other report required by Specification-6.9.1,--a Special Report is prepared and submitted to the Commission pursuant to Specification 6.9.2 within 10 days, describing the value of the measured MTC, the interim control rod withdrawal limits and the predicted average core burnup necessary for restoring the positive MC to within its limit for the all rods withdrawn condition.
: b. With the MTC more negative than the ZOL limit specified in   the COLR, be in HOT SHUTDOWN within 12 hours.
*With Kact greater than or equal to 1.0
#See Special Test Exception 3.10.3 SALEM - UNIT 2                  3/4 L-4                  Amendment No J97

RI-ACTTVITY CONTR~OL SYSTEMS MODERATOR ZMME~TtMZ COEFFICZENT SURVEILLANCE REQUIzREMENTS 4.1.1.3 The MTC shall be determined to be within its     limits during each fuel cycle as follow&:
: a. The MTC shall be measured and cmpared to the BOL limit specified iLn the COLR prior to initial   operation above 5% of RATED THERMAL POWER, after each fuel loadinG.
: b. The )CC shall be measured at any THEM-AL POWER and compared to the 300 ppm surveillance limit  specified in the COLR (all rods withdravn, RATED THETML POWER condition) within 7 EFPD after reaching an equilibrium boron concentration of 300 ppm. In the event this comparison indicates the MTC is more negative than the 300 ppam surveillance limit specified in the COLR, the MTC shall be remeasured, and compared to the ZOL MTC limit specified in the COLR   i at least once per 14 EFPD during the remainder of the fuel cycle.
SALEM - UNIT 2                         3/4 1-5                 Amendment No .197

REACTIVITY CONTROL SYSTEMS MINIMUM TEMPERATURE FOR CRITICALITY LIMITING CONDITION FOR OPERATION 3.1.1.4 The Reactor Coolant System lowest operating loop temperature (Tavg) shall be greater than or equal to 5410 F.
APPLICABILITY:     MODES I and 2 ACTION:
With a Reactor Coolant System operating loop temperature (T      ) less than 5410F, restore T       to within its limit within 15 minutes ofvge in HOT STANDBY within the next 1gminutes.
SURVEILLANCE REOUIREMENTS 4.1.1.4     The Reactor Coolant System temperature (Tavg) shall be determined to be greeter than or equal to 5410F:
: a. Within 15 minutes prior to achieving reactor criticality, and
: b. At least once per 30 minutes when the reactor is critical and the Reactor Coolant System T    is less than 551*F with the Tavg - Tref Deviation Alarm not reseyga
#With K       greater than or equal to 1.0.
 *See SpAMIal Test Exception 3.10.3.
SALEM   - UNIT 2                     3/4 1-6

REACTIVITY CONTROL SYSTEMS 3/4.1.2 BORATION SYSTEMS FLOW PATHS - SHUTDOWN LMITING-CQNDITION FOR OPERATION 3.1.2.1 As a minimum, one of the following boron injection flow paths shall be OPERABLE:
: a. A flow path from the boric acid tanks via a boric acid transfer pump and a charging pump to the Reactor Coolant System if the boric acid storage system is OPERABLE, per Specification 3.1.2.6a while in MODE 4, or per Specification 3.1.2.5a while in MODE 5 or 6, or
: b. A flow path from the refueling water storage tank via a charging pump to the Reactor Coolant System if the refueling water storage tank is OPERABLE per Specification 3.1.2.6b while in MODE 4, or per Specification 3.1.2.5b while in MODE 5 or 6.
APPLICABILITY: MODES 4, 5 and 6.
ACTION:
With none of the above flow paths OPERABLE, suspend all operations involving CORE ALTERATIONS or positive reactivity changes until at least one injection path is restored to OPERABLE status.
_.UI_RVEI LLANC E RELQUIREMENTS 4.1.2.1 At least one of the above required flow paths shall be demonstrated OPERABLE:
: a. When the boric acid tank is a required water source, by verifying in accordance with the Surveillance Frequency Control Program that:
(1)     The flow path -from the boric acid tank to the boric acid transfer pump, the boric acid transfer pump, and the recirculation path from the boric acid transfer pump to the boric acid tank is > 630F, and (2)     The flow path between the boric acid transfer pump recirculation line to the charging pump suction line is >- 50 0 F,
: b. In accordance with the Surveillance Frequency Control Program by verifying that each valve (manual, power operated or automatic) in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position.
SALEM - UNIT 2                                314 1-7                          Amendment No. 282

REACTIVITY CONTROL SYSTEMS FLOW PATHS - OPERATING LIMITING CON DII ON FOR OPERATION 3.1.2.2 At least two of the following three boron injection flow paths shall be OPERABLE:
: a.      A flow path from the boric acid tanks via a boric acid transfer pump and a charging pump to the Reactor Coolant System.
: b.      Two flow paths from the refueling water storage tank via charging pumps to the Reactor Coolant System.
APPLICABILITY: MODES 1, 2 and 3.
ACTION:
With only one of the above required boron injection flow paths to the Reactor Coolant System OPERABLE, restore at least two boron injection flow paths to the Reactor Coolant System to OPERABLE status within 72 hours or be in at least HOT STANDBY and borated to a SHUTDOWN MARGIN equivalent to at least 1% delta k/k at 200'F within the next 6 hours; restore at least two flow paths to OPERABLE status within the next 7 days or be in COLD SHUTDOWN within the next 30 hours.
SURVEILLANCE REQUIREMENTS 4.1.2.2 Each of the above required flow paths shall be demonstrated OPERABLE:
: a.      By verifying in accordance with the Surveillance Frequency Control Program that:
(1)     The flow path from the boric acid tank to the boric acid transfer pump and from the recirculation line back to the boric acid tank is 2>63&deg;F, and (2)     The flow path between the boric acid tank recirculation line to the charging pump suction line is ? 50'F,
: b.      In accordance with the Surveillance Frequency Control Program by verifying that each valve (manual, power operated or automatic) in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position.
: c.      In accordance with the Surveillance Frequency Control Program during shutdown by verifying that each automatic valve in the flow path actuates to its correct position on a safety injection test signal.
: d.      In accordance with the Surveillance Frequency Control Program by verifying that the flow path required by Specification 3.1.2.2.a delivers at least 33 gpm to the Reactor Coolant System.
SALEM - UNIT 2                                  3/4 1-8                         Amendment No. 282

REACTIVITY CONTROL SYSTEMS CHARGING PUMP - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.1.2.3 At least one charging pump in the boron injection flow path required by Specification 3.1.2.1 shall be OPERABLE.!
APPLICABILITY: MODES 4, 5 and 6.
ACTION:
With no charging pump OPERABLE, suspend all operations involving CORE ALTERATIONS or positive reactivity changes until one charging pump is restored to OPERABLE status.
SURVEILLANCE REQUIREMENTS 4.1.2.3 No additional Surveillance Requirements other than those required by the Inservice Testing Program.
#       A maximum of one centrifugal charging pump shall be OPERABLE while in MODE 4 when the temperature of one or more of the RCS cold legs is less than or equal to 312'F, MODE 5, or MODE 6 when the head is on the reactor vessel.
SALEM - UNIT 2                                3/4 1-9                       Amendment No. 279

REACTIVITY CONTROL SYSTEMS CHARGING PUMPS - OPERATING LIMITING CONDITION FOR OPERATION 3.1.2.4 At least two charging pumps shall be OPERABLE.
APPLICABILITY: MODES 1, 2 and 3.
ACTION:
With only one charging pump OPERABLE, restore at least two charging pumps to OPERABLE status within 72 hours or be in at least HOT STANDBY and borated to a SHUTDOWN MARGIN equivalent to at least 1 % delta k/k at 200&deg;F within the next 6 hours; restore at least two charging pumps to OPERABLE status within the next 7 days or be in COLD SHUTDOWN within the next 30 hours.
SURVEILLANCE REQUIREMENTS 4.1.2.4 No additional Surveillance Requirements other than those required by the Inservice Testing Program.
SALEM - UNIT 2                                3/4 1-10                         Amendment No. 279

REACTIVITY CONTROL SYSTEMS BORATED WATER SOURCES - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.1.2.5 As a minimum, one of the following borated water sources shall be OPERABLE:
: a. A boric acid storage system with:
: 1.      A minimum contained volume of 2,600 gallons,
: 2.      Between 6,560 and 6,990 ppm of boron, and
: 3.      A minimum solution temperature of 63&deg;F.
: b. The refueling water storage tank with:
: 1.      A minimum contained volume of 37,000 gallons,
: 2.      A minimum boron concentration of 2,300 ppm, and
: 3.      A minimum solution temperature of 350F.
APPLICABILITY: MODES 5 and 6.
ACTION:
With no borated water source OPERABLE, suspend all operations involving CORE ALTERATIONS or positive reactivity changes until at least one borated water source is restored to OPERABLE status.
SURVEILLANCE REQUIREMENTS 4.1.2.5 The above required borated water source shall be demonstrated OPERABLE:
: a. For the boric acid storage system, when it is the source of borated water in accordance with the Surveillance Frequency Control Program by:
: 1.      Verifying the boron concentration of the water,
: 2.      Verifying the water level of the tank, and
: 3.      Verifying the boric acid storage tank solution temperature when it is the source of borated water.
: b. For the refueling water storage tank by:
: 1.      Verifying the boron concentration in accordance with the Surveillance Frequency Control Program,
: 2.      Verifying the borated water volume in accordance with the Surveillance Frequency Control Program, and
: 3.      Verifying the solution temperature in accordance with the Surveillance Frequency Control Program, when it is the source of borated water and the outside air temperature is less than 350F.
SALEM - UNIT 2                               3/4 1-11                        Amendment No. 282

REACTIVITY CONTROL SYSTEMS BORATED WATER SOURCES - OPERATING LIMITING CONDITION FOR OPERATION 3.1.2.6 As a minimum, the following borated water source(s) shall be OPERABLE as required by Specifications 3.1.2.1 and 3.1.2.2:
: a.       A boric acid storage system with:
: 1.       A contained volume of borated water in accordance with figure 3.1-2,
: 2.       A Boron concentration in accordance with Figure 3.1-2, and
: 3.       A minimum solution temperature of 630F.
: b.       The refueling water storage tank with:
: 1.       A contained volume of between 364,500 and 400,000 gallons of water,
: 2.       A boron concentration of between 2,300 and 2,500 ppm, and
: 3.       A minimum solution temperature of 35'F.
APPLICABILITY:      , MODES 1, 2, 3 and 4.
ACTION:
: a.       With the boric acid storage system inoperable and being used as one of the above required borated water sources, restore the storage system to OPERABLE status within 72 hours or be in at least HOT STANDBY within the next 6 hours and borated to a SHUTDOWN MARGIN equivalent to at least 1% delta k/k at 2007F; restore the boric acid storage system to OPERABLE status within the next 7 days or be in COLD SHUTDOWN within the next 30 hours.
: b.       With the refueling water storage tank inoperable, restore the tank to OPERABLE status within one hour or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
U&BEMILLAUQ.CEREQIUJI REM ENTS 4.1.2.6 Each borated water source shall be demonstrated OPERABLE:
: a.       For the boric acid storage system, when it is the source of borated water in accordance with the Surveillance Frequency Control Program by:
: 1.       Verifying the boron concentration in each water source.
: 2.       Verifying the water level of each water source, and
: 3.       Verifying the boric acid storage system solution temperature.
: b.      For the refueling water storage tank by:
: 1.       Verifying the boron concentration in accordance with the Surveillance Frequency Control Program,
: 2.       Verifying the borated water volume in accordance with the Surveillance Frequency Control Program, and
: 3.       Verifying the solution temperature in accordance with the Surveillance Frequency Control Program when the outside air temperature is less than 35 0 F.
SALEM - UNIT 2                                     3/4 1-12                           Amendment No. 282

BORIC ACID TANK CONTENTS BASED ON RWST CONCENTRATION urn Sp               p             p I
                           . ..              .            AC                  Ap       .           R z
looss   100%                                                                                                                     7,8000 z                                   S;  SnS.        .              m           .. .      ..         ...
* U 98%    (                                                                                                                 7,600 w
                     *  ..     "~-        r......,.......
I
 .-j    95%                                                                                                                      7,400Z a-                         ,    * ~IS'                ..         ,      -,,.         -%*
C
                   'a a .                           P,         .                 "% /     , %          ..
0     92%                                                                                                                         7.00 w                          ,          .6.i    ./                                          ,            *.
                            ,       9%,             , p         .                                     %          -
i             p         ,                . i9%~/                          *              ,       7,000 Wj 90%
0 lo-
                                 ,        ,       2350 ==am / I>                                       .            ;,
u.j                              ,        ,       24B!,!ppm ,*'                ,"   I    -                         %;_*
87%
                        -;    so          tp      Cm    ni*    rr                                                             ,000 2500 ppm
                                                               ......           .. . ....... .....                              l, f
0                           :6990
                            ,0                                             ppm ."mu''-,,..            s z      85%
I'          i             '          699O pp            (mllximum)i-.-O I-I 7 '.000 6,800                    6,700                      8.800                   6,900 CONCENTRATION IN BAT                                                               -      ppm BORON SALEM - UNIT 2                                          Figure 3.1-2 314 1.12(a)                    Arwndr*nt No.            133

3REAC3TI   4V)TY..
314.1.3=L         OqA*XS A3TESZ@S
* CONTROL           *::1 LnCTWG CMZITION FOR OPRAZTION 3.1.3.1 All full length (shutdown and control) rods, shall be OPZRA=LZ and positioned w*.thin 2 16 steps (ind1icated        position) when reactor p"wer Is s 95%
PATM Ti13*4L P01WU, or
* 12 stops (indicated position) when reactor power in
> 850 PAM.D T*t       L POW=, of thisi group step counter dmand position Wit-in ca- hour after rod motion.
h~x       ZbW:MS            le and 2*
: a. With one or nore    full length rods inoperable due to being immovable as a result of excessive friction or mechanical interferenoe or known to be untrippable, determino that the SHUTDOUN W0J=X requirement of Specification 3.1.1.1 is satisfied within 1 hour and be in HOT STA)(0Y within S hours.
     .b. With more than one full length rod inoperable or mis-aligned fzzm the group stop counter demand position by more than
* 18 steps (indicated position) at z 85% PWM THM744RL POWE or t 12 steps (indicated position) at > 85b RATSD *H3*ML POWR, be in HOT STANBY within 6 hous.
C. With one full    length rod inoperable due to causes other than addressed by ACTION a, above, or -ia-aligned fro.s its growp step counter demand position by more than t 1 steps (indicated position) at s 85% RATZD TM1= 4 L PO0SR or +/- 12 steps (indicated position)-at
             > e3% RATZD THiMAmL 1011R, PO13 OPflATZI         may continue provided that within one hour either:
: 1. The red is   restored to OPRAZZ status within the above alignment requirements,      or
: 2. The zemainder of the rods in the bank with the inoperable rod are aligned to within t 16 steps (indicated position) at s 85%
PA= TUUL 106Z3 ort t 12 stops (Indicated position) at >05b RAM'S   TM13NML 1011,     of the Inoperable rod wbtle maintainIng the rod sequence and insertion limits in the CC=a per Spe~ca.fstion 3.1.3.5. the THWRL VO3. level *sh*'lbe restricted pus**ant to Specificatioa 3.1.3.5 during subsoequst
: 3. The rod is declared inoperable and the M2ITDOW WWrM requirement of Specification 3.1.1.1 is satisfied. 100M3 OpPIATIOt may then continue provided that:
*See Speci&l Test zxception         3.10.2   and 3.10.3.
BALCH - U=T 2                         3/4 1-13                        23Aenisent xo. 197

REACTIVITY CONTROL SYSTEMS LIMITING CONDITION FOR OPERATION (Continued) a)     A reevaluation of each accident analysis of Table 3.1-1 is performed within 5 days; this reevaluation shall confirm that the previously analyzed results of these accidents remain valid for the duration of operation under these conditions.
b)     The SHUTDOWN MARGIN requirement of Specification 3.1.1.1 is determined at least once per 12 hours.
c)     A core power distribution measurement is obtained and FQ(Z) and FNAH are verified to be within their limits within 72 hours.
d)     The THERMAL POWER level is reduced to less than or equal to 75% of RATED THERMAL POWER within one hour and within the next 4 hours the high neutron flux trip setpoint is reduced to less than or equal to 85% of RATED THERMAL POWER. THERMAL POWER shall be maintained less than or equal to 75% of RATED THERMAL POWER until compliance with ACTIONS 3.1.3.1.c.3.a and 3.1.3.1.c.3.c above are demonstrated.
SURVEILLANCE REQUIREMENTS 4.1.3.1.1 The position of each full length rod shall be determined to be within the limits established in the limiting condition for operation in accordance with the Surveillance Frequency Control Program (allowing for one hour thermal soak after rod motion) except during time intervals when the Rod Position Deviation Monitor is inoperable, then verify the group positions at least once per 4 hours.
4.1.3.1.2 Each full length rod not fully inserted in the core shall be determined to be OPERABLE by movement of at least 10 steps in any one direction in accordance with the Surveillance Frequency Control Program.
SALEM - UNIT 2                                 3/4 1-14                           Amendment No. 282

TABLE 3.1-1 ACCIDENT ANALYSES REW.IR.NG REEVALUATION IN THE EVENT OF AN I.NOPERABLE FULL LENGTH ROD Rod Cluster Control Assembly Insertion Characteristics Rod Cluster Control Assembly Nis-alignment Loss Of Reactor Coolant From Ruptured Pipes Or From Cracks In Large Pipes Mitch Actuates The Emergency Core Cooling System Single Rod Cluster Control Assembly Withdrawal At Full Power Major Reactor Coolant System Pipe Ruptures (Loss Of Coolant Accident)
Major Secondary System Pipe Rupture Rupture of a Control Rod Drive Mechanism Ibusing (Rod Cluster Control Assembly Ejection)
SALEM - UNIT 2                          3/4 1-15         Amendment No. 48

REACTIVITY CONTROL SYSTEMS POSITION INDICATION SYSTEMS - OPERATING LIMITING CONDITION FOR OPERATION 3.1.3.2.1 The shutdown and control rod position indication systems shall be OPERABLE and capable of determining the actual and demanded rod positions as follows:
: a. Analog rod position indicators, within one hour after rod motion (allowance for thermal soak);
All Shutdown Banks: +/- 18 steps at *85% reactor power or if reactor power is > 85% RATED THERMAL POWER +/- 12 steps of the group demand counters for withdrawal ranges of 0-30 steps and 200-230 steps.
Control Bank A: +/- 18 steps at 585% reactor power or if reactor power is
       > 85% RATED THERMAL POWER +/- 12 steps of the group demand counters for withdrawal ranges of 0-30 steps and 200-230 steps.
Control Bank B: +/- 18 steps at a85% reactor power or if reactor power is
       > 85% RATED THERMAL POWER +/- 12 steps of the group demand counters for withdrawal ranges of 0-30 steps and 160-230 steps.
Control Banks C and D: +/- 18 steps at *85% reactor power or if reactor power is > 85% RATED THERMAL POWER +/- 12 steps of the group demand counters for withdrawal range of 0-230 steps.
: b. Group demand counters; +/- 2 steps of the pulsed output of the Slave Cycler Circuit over the withdrawal range of 0-230 steps.
APPLICABILITY: MODES 1 and 2.
ACTION:
: a. With a maximum of one analog rod position indicator per bank inoperable either:
: 1. Determine the position of the non-indicating rod(s) indirectly using the power distribution monitoring system (if power is above 25% RTP) or using the movable incore detectors (if power is less than 25% RTP or the power distribution monitoring system is inoperable) at least once per 8 hours and within one hour after any motion of the non-indicating rod which exceeds 24 steps in one direction since the last determination of the rod's position, or
: 2. Reduce THERMAL POWER to less than 50% of RATED THERMAL POWER within 8 hours.
: b. With two or more analog rod position indicators per bank inoperable, within one hour restore the inoperable rod position indicator(s) to OPERABLE status or be in HOT STANDBY within the next 6 hours. A maximum of one rod position indicator per bank may remain inoperable following the hour, with Action (a) above being applicable from the original entry time into the LCO.
SALEM - UNIT    2                    3/4 1-16                  Amendment No. 276

REACTIVITY CONTROL SYSTEMS LIMITING CONDITION FOR OPERATION (Continued)
: c.      With a maximum of one group demand position indicator per bank inoperable either:
: 1. Verify that all analog rod position indicators for the affected bank are OPERABLE and that the most withdrawn rod and the least withdrawn rod of the bank are within a maximum of 18 steps when reactor power is 5 85% RATED THERMAL POWER or if reactor power is > 85% RATED THERMAL POWER, 12 steps of each other at least once per 8 hours, or
: 2. Reduce THERMAL POWER to less than 50% of RATED THERMAL POWER within 8 hours.
SURVEILLANCE REQUIREMENTS 4.1.3.2.1.1 Each analog rod position indicator shall be determined to be OPERABLE by verifying that the demand position indication system and the rod position indication system agree within 18 steps when reactor power is < 85% RATED THERMAL POWER or if reactor power is > 85% RATED THERMAL POWER, 12 steps (allowing for one hour thermal soak after rod motion) in accordance with the Surveillance Frequency Control Program except during time intervals when the Rod Position Deviation Monitor is inoperable, then compare the demand position indication system and the rod position indication system at least once per 4 hours.
4.1.3.2.1.2 Each of the above required rod position indicator(s) shall be determined to be OPERABLE by performance of a CHANNEL calibration in accordance with the Surveillance Frequency Control Program.
SALEM - UNIT 2                                 3/4 1-16a                          Amendment No. 282

THIS PAGE INTENTIONALLY LEFT BLANK SALEM - UNIT 2 3/4 1-17 Amendment No. 213

REACTIVITY CONTROL SYSTEMS ROD DROP TIME LIMITING CONDITION FOR OPERATION 3.1.3.3 The individual full length (shutdown and control) rod drop time from 230 steps withdrawn shall be less than or equal to 2.7 seconds from beginning of decay of stationary gripper coil voltage to dashpot entry with:
: a.       Tavg greater than or equal to 541&deg;F, and
: b.       All reactor coolant pumps operating.
APPLICABILITY: MODES 1 & 2.
ACTION:
: a.       With the drop time of any full length rod determined to exceed the above limit, restore the rod drop time to within the above limit prior to proceeding to MODE 1 or2.
: b.       With the rod drop times within limits but determined with 3 reactor coolant pumps operating, operation may proceed provided THERMAL POWER is restricted to less than or equal to 76% of RATED THERMAL POWER.
SURVEILLANCE REQUIREMENTS 4.1.3.3 The rod drop time of full length rods shall be demonstrated through measurement prior to reactor criticality:
: a.       For all rods following each removal of the reactor vessel head,
: b.       For specifically affected individual rods following any maintenance on or modification to the control rod drive system which could affect the drop time of those specific rods, and
: c.       In accordance with the Surveillance Frequency Control Program.
SALEM - UNIT 2                                  3/4 1-18                         Amendment No. 282

REACTIVITY CONTROL SYSTEMS SHUTDOWN ROD INSERTION LIMIT LIMITING CONDITION FOR OPERATION 3.1.3.4 All shutdown rods shall be FULLY WITHDRAWN.
APPLICABILITY: MODES 1*, and 2*#@.
ACTION:
With a maximum of one shutdown rod not FULLY WITHDRAWN, except for surveillance testing pursuant to Specification 4.1.3.1.2, within one hour either:
: a.       FULLY WITHDRAW the rod, or,
: b.       Declare the rod to be inoperable and apply Specification 3.1.3.1.
SURVEILLANCE REQUIREMENTS 4.1.3.4 Each shutdown rod shall be determined to be FULLY WITHDRAWN by use of the group demand counters, and verified by the analog rod position indicators**:
: a.       Within 15 minutes prior to withdrawal of any rods in control banks A, B, C, and D during an approach to reactor critically, and
: b.       In accordance with the Surveillance Frequency Control Program thereafter.
See Special Test Exceptions 3.10.2 and 3.10.3.
**      For power levels below 50% one hour thermal "soak time" is permitted. During this soak time, the absolute value of rod motion is limited to six steps.
@       Surveillance 4.1.3.4.a is applicable prior to withdrawing any control banks in preparation for startup (Mode 2).
#       With Keff greater than or equal to 1.0.
Note:   This page effective prior to startup from fifth refueling outage scheduled to begin March 1990. Letter dated Jan. 11, 1990.
SALEM - UNIT 2                                 3/4 1-19                        Amendment No. 282

REACTIVITY CONTROL SYSTEMS CONTROL ROD INSERTION LIMITS LIMITING CONDITION FOR OPERATION 3.1.3.5 The control banks shall be limited in physical insertion as specified in the CORE OPERATING LIMITS REPORT (COLR).
APPLICABILITY: MODES 1, and 2*#
ACTION:
With the control banks inserted beyond the above insertion limits, except for surveillance testing pursuant to Specification 4.1.3.1.2, either:
: a. Restore the control banks to within the limits within two hours, or
: b. Reduce THERMAL POWER within two hours to less than or equal to that fraction of RATED THERMAL POWER which is allowed by the bank position using the insertion limits specified in the CLOR, or
: c. Be in at least HOT STANDBY within 6 hours.
SURVEILLANCE REQUIREMENTS 4.1.3.5 The position of each control bank shall be determined to be within the insertion limits in accordance with the Surveillance Frequency Control Program by use of the group demand counters and verified by the analog rod position indicators** except during time intervals when the Rod Insertion Limit Monitor is inoperable, then verify the individual rod positions at least once per 4 hours".
See Special Test Exceptions 3.10.2 and 3.10.3
**      For power levels below 50% one hour thermal "soak time" is permitted. During this soak time, the absolute value of rod motion is limited to six steps.
#       With Keff greater than or equal to 1.0 SALEM - UNIT 2                                  314 1-20                       Amendment No. 282

THIS PA=Z M  NTIOHK=T LEFT RLAW1 SALEM - UNIT 2             3/4 1-21             Amendment No. 197

THI~S PA=Z MNTEITONALLT LEFT ULWX 3/4 1-22         Am&neommnt N0.197 SAZ.ZM - UNIT 2

314.2 POWER DISTRIBUTION LIMITS 3/4.2.1 AXIAL FLUX DIFFERENCE (AFD)
LIMITING CONDITION FOR OPERATION 3.2.1 The indicated AXIAL FLUX DIFFERENCE shall be maintained within the target band about the target flux difference as specified in the CORE OPERATING LIMITS REPORT (COLR).
APPLICABILITY: MODE 1 ABOVE 50% RATED THERMAL POWER*
ACTION:
: a. With the indicated AXIAL FLUX DIFFERENCE outside of the target band about the target flux difference as specified in the COLR and with THERMAL POWER:
: 1.      Above 90% of RATED THERMAL POWER, within 15 minutes:
a)      Either restore the indicated AFD to within the target band limits, or b)      Reduce THERMAL POWER to less than 90% of RATED THERMAL POWER.
: 2.       Between 50% and 90% of RATED THERMAL POWER:
a)      POWER OPERATION may continue provided:
: 1)      The indicated AFD has not been outside of the target band as specified in the COLR for more than 1 hour penalty deviation cumulative during the previous 24 hours, and
: 2)      The indicated AFD is within the limits as specified in the COLR. Otherwise, reduce THERMAL POWER to less than 50% of RATED THERMAL POWER within 30 minutes and reduce the Power Range Neutron Flux-High Trip Setpoints to less than or equal to 55% of RATED THERMAL POWER within the next 4 hours.
b)      Surveillance testing of the Power Range Neutron Flux Channels may be performed pursuant to Specification 4.3,1.1.1 provided the indicated AFD is maintained within the limits as specified in the COLR. A total of 16 hours operation may be accumulated with the AFD outside of the target band during this testing without penalty deviation.
See Special Test Exception 3.10.2 SALEM - UNIT 2                                  3/4 2-1                        Amendment No. 278

POWER DISTRIBUTION LIMITS LIMITING CONDITION FOR OPERATION (Continued)
: b. THERMAL POWER shall not be increased above 90% of RATED THERMAL POWER unless the indicated AFD is within the target band as specified in the COLR and ACTION a.2.a) 1), above has been satisfied.
: c. THERMAL POWER shall not be increased above 50% of RATED THERMAL POWER unless the indicated AFD has not been outside of the target band as specified in the COLR for more than 1 hour penalty deviation cumulative during the previous 24 hours. Power increases above 50% of RATED THERMAL POWER do not require being within the target band provided the accumulative penalty deviation is not violated.
_URVEILLANCE REQUIREMENTS 4.2,1.1 The indicated AXIAL FLUX DIFFERENCE shall be determined to be within its limits during POWER OPERATION above 15% of RATED THERMAL POWER by:
: a. Monitoring the indicated AFD for each OPERABLE excore channel:
: 1.      In accordance with the Surveillance Frequency Control Program when the AFD Monitor Alarm is OPERABLE, and
: 2.       In accordance with the Surveillance Frequency Control Program for the first 24 hours after restoring the AFD Monitor Alarm to OPERABLE status.
: b. Monitoring and logging the indicated AXIAL FLUX DIFFERENCE for each OPERABLE excore channel in accordance with the Surveillance Frequency Control Program for the first 24 hours and in accordance with the Surveillance Frequency Control Program thereafter, when the AXIAL FLUX DIFFERENCE Monitor Alarm is inoperable. The logged values of the indicated AXIAL FLUX DIFFERENCE shall be assumed to exist during the interval preceding each logging, 4.2.1.2 The indicated AFD shall be considered outside of its target band when at least 2 or more OPERABLE excore channels are indicating the AFD to be outside the target band.
Penalty deviation outside of the target band shall be accumulated on a time basis of:
: a. One minute penalty deviation for each one minute of POWER OPERATION outside of the target band at THERMAL POWER levels equal to or above 50% of RATED THERMAL POWER, and
: b. One-half minute penalty deviation for each one minute of POWER OPERATION outside of the target band at THERMAL POWER levels below 50% of RATED THERMAL POWER.
SALEM - UNIT 2                                  3/4 2-2                      Amendment No. 282

POWER DISTRIBUTION LIMITS SLURVEILLANCE REQUIREMENTS (Continued) 4.2.1.3 The target flux difference of each OPERABLE excore channel shall be determined by measurement in accordance with the Surveillance Frequency Control Program. The provisions of Specification 4.0.4 are not applicable.
4.2.1.4 The target flux difference shall be updated in accordance with the Surveillance Frequency Control Program by either determining the target flux difference pursuant to 4.2.1.3 above or by linear interpolation between the most recently measured value and 0% at the end of the cycle life. The provisions of Specification 4.0.4 are not applicable.
SALEM - UNIT 2                                 3/4 2-3                      Amendment No. 282

THIS PAGE fl    T7.OZALLy LZFT 3IalUW SAUEM - UNIT 2              3/4 2-4              3/42-4Amendmen No.197

POWER DISTRIBUTION LIMITS 3/4.2.2   HEAT FLUX HOT CHANNEL FACTOR - FQ(Z)
LIMITING CONDITION FOR OPERATION 3.2.2      FQ (z)  <    FoTp
* K(z)   for P   >  0.5, and P
FQ  (z) _<      RTP
* K(z)   for P   <  0.5, and 0.5 Where FQRTP = the FQ limit at RATED THERMAL POWER (RTP)         specified in the CORE OPERATING LIMITS REPORT (COLR),
P             THERMAL POWER       ,  and RATED THERMAL POWER K(z)    the normalized FQ(z)        as a function of core height as specified in the COLR.
APPLICABILITY: MODE    .
ACTION:
With FQ(Z) exceeding its       limit:
: a. Reduce THERMAL POWER at least 1% for each 1% FQ(Z) exceeds the limit within 15 minutes and similarly reduce the Power Range Neutron Flux-High Trip Setpoints within the next 4 hours; POWER OPERATION may proceed for up to a total of 72 hours; subsequent POWER OPERATION may proceed provided the Overpower delta T Trip Setpoints have been reduced at least 1% for each 1% FQ(Z) exceeds the limit. The Overpower delta T Trip Setpoint reduction shall be performed with the reactor in at least HOT STANDBY.
: b. Identify and correct the cause of the out of limit condition prior to increasing THERMAL POWER above the reduced limit required by a.
above; THERMAL POWER may then be increased provided FQ(Z) is demonstrated through a core power distribution measurement to be within its   limit.
SALEM - UNIT 2                             3/4 2-5                   Amendment No. 239

POWER DISTRIBUTION LIMITS SURVEILLANCE REQUIREMENTS 4.2.2.1 The provisions of Specification 4.0.4 are not applicable.
4.2.2.2 Fxy shall be evaluated to determine if FQ(Z) is within its limit by:
: a.      Using the movable incore detectors to obtain a power distribution map:
: 1. When THERMAL POWER is < 25%, but > 5% of RATED THERMAL POWER, or
: 2.       When the Power Distribution Monitoring System (PDMS) is inoperable; and increasing the Measured FQ(Z) by the applicable manufacturing and measurement uncertainties as specified in the COLR.
: b.      Using the PDMS or the moveable incore detectors when THERMAL POWER is > 25% of RATED THERMAL POWER, and increasing the measured FQ(Z) by the applicable manufacturing and measurement uncertainties as specified in the COLR.
: c.      Comparing the Fy computed (Fxyc) obtained in b, above to:
: 1.      The Fxy limits for RATED THERMAL POWER (FXYRTP) for the appropriate measured core planes given in e. and f., below, and
: 2.       The relationship:
Fx, L = FXIRTP [ 1 + PFxy (1-P)]
where Fxy Lis the limit for fractional THERMAL POWER operation expressed as a function of FXYRTP, PFx, is the power factor multiplier for Fxy in the COLR, and P is the fraction of RATED THERMAL POWER at which Fxy was measured.
: d.      Remeasuring Fx, according to the following schedule:
: 1. When Fxyc is greater than the FXYRTP limit for the appropriate measured core plane but less than the FxL relationship, additional core power distribution measurements shall be taken and Fxyc compared to FXYRTP and FxyL:
a)      Either within 24 hours after exceeding by 20% of RATED THERMAL POWER or greater, the THERMAL POWER at which Fxyc was last determined, or b)      In accordance with the Surveillance Frequency Control Program, whichever occurs first.
SALEM - UNIT 2                                     3/4 2-6                     Amendment No. 282

POWER DISTRIBUTION LIMITS SURVEILLANCE REQUIREMENTS (Continued)
: 2.      When the Fyc is less than or equal to the FXyRTP limit for the appropriate measured core plane, additional core power distribution measurements shall be taken and F,~,c compared to F'yRTP and FYL in accordance with the Surveillance Frequency Control Program.
: e. The Fxy limit for Rated Thermal Power (FyRTP) shall be provided for all core planes containing bank "D" control rods and all unrodded core planes in the COLR per specification 6.9.1.9.
: f. The FXY limits of e., above, are not applicable in the following core plane regions as measured in percent of core height from the bottom of the fuel:
: 1. Lower core region from 0% to 15%, inclusive.
: 2.      Upper core region from 85% to 100%, inclusive.
: 3.      Grid plane regions at 17.8% +/- 2%, 32.1% +/- 2%, 46.4% +/- 2%,
60.6% +/- 2% and 74.9% +/- 2%, inclusive.
: 4.      Core plane regions within +/- 2% of core height (+/- 2.88 inches) about the bank demand position of the bank "D"control rods.
: g. Evaluating the effects of FI on Fa(Z) to determine if FQ(Z) is within its limit whenever FXc exceeds FXY .
4.2.2.3 When F0 (Z) is measured pursuant to specification 4.10.2.2, an overall measured FQ(Z) shall be obtained from a core power distribution measurement and increased by the applicable manufacturing and measurement uncertainties as specified in the COLR.
SALEM - UNIT 2                                 3/4 2-7                          Amendment No. 282

THIS PA= MMNTZONMIY LE77 SLAWU SAL04 - UNI~T 23/2-              3/4 2-9           Amendmnt iuo .19 7

POWER DISTRIBUTION LIMITS 3/14.2.3 NUCLEAR ENTRALPY HOT CHANNEL FACTOR F'aH LIMITING CONDITION FOR OPERATION 3.2.3       emF shall be limited by the following relationship:
F11&1, =         C1.0 *+ F   (1, 0 - P)I Where:    FRTP H is the limit at RATED THERMAL POWER in the Core Operating Limits Report (COLR).
PFam is the Power Factor Multiplier for FN6H specified in the COLR, and P is     THERMAL POWER RATED THERMAL POWER APPLICABILITY:            MODE I ACTION:
With FNaH exceeding its limit:
: a. Reduce THERMAL POWER to less than 50% of RATED THERMAL POWER within 2 hours and reduce the Power Range Neutron Flux-High Trip Setpoints to 9 55% of RATED THERMAL POWER within the next 4 hours.
: b. Demonstrate through a core power distribution measurement that F is within its limit within 24 hours after exceeding the limit or reduce THERMAL POWER to less than 5% of RATED THERMAL POWER within the next 2 hours, and
: c. Identify and correct the cause of the out of limit condition prior to increasing THERMAL POWER above the reduced limit required by a.
or b. above; subsequent POWER OPERATION may proceed provided that F N6H is demonstrated through a core power distribution measurement to be within its limit at a nominal 50% of RATED THERMAL POWER prior to exceeding this THERMAL POWER, at a nominal 75% of RATED THERMAL POWER prior to exceeding this THERMAL POWER and within 24 hours after attaining 95t or greater RATED THERMAL POWER.
SALEM - UNIT2                             3/4 2-9                 Amendment No. 215

POWER DISTRIBUTION LIMITS SURVEILLANCE REQUIREMENTS 4.2.3.1 FN Hshall be determined to be within its limit by obtaining a core power distribution measurement:
: a.      Prior to operation above 75% of RATED THERMAL POWER after each fuel loading, and
: b.      In accordance with the Surveillance Frequency Control Program.
: c.      The provisions of Specification 4.0.4 are not applicable.
4.2.3.2 The measured FNAH of 4.2.3.1 above, shall be increased by the applicable FNtH uncertainties* specified in the COLR.
For Cycle 11, when the number of available movable detector thimbles is greater than or equal to 50% and less than 75% of the total, the 4% measurement uncertainty shall be increased to [4% + (3-T/14.5)(1%)] where T is the number of available thimbles.
SALEM - UNIT 2                                3/4 2-10                       Amendment No. 282

PAGE INTENTIONALLY BLANK SALEM UNIT 2    3/4 2-11              Amendment No. 72

PAGE INTENTIONALLY BLANK SALEM UNIT 2    3/4 2,-12             Amendment No. 72

POWER DISTRIBUTION LIMITS 3/4.2.4    QUADRANT POWER TILT RATIO LIMITING CONDITION FOR OPERATION 3.2.4    The QUADRANT POWER TILT RATIO shall not exceed 1.02.
APPLICABILITY:     MODE 1 above 50% of RATED THERMAL POWER*.
ACTION:
: a. With the QUADRANT POWER TILT RATIO determined to exceed 1.02 but less than or equal to 1.09:
: 1. Calculate the QUADRANT POWER TILT RATIO at least once per hour until:
a)    Either the QUADRANT POWER TILT RATIO is reduced to within its limit, or b)    THERMAL POWER is reduced to less than 50% of RATED THERMAL POWER.
: 2. Within 2 hours:
a)    Either reduce the QUADRANT POWER TILT RATIO to within its limit, or b)    Reduce THERMAL POWER at least 3% from RATED THERMAL POWER for each 1% of indicated QUADRANT POWER TILT RATIO in excess of 1.0 and similarly reduce-the Power Range Neutron Flux-High Trip Setpoints within the next 4 hours.
: 3. a)   Verify that the QUADRANT POWER TILT RATIO is within its limit within 24 hours after exceeding the limit or reduce THERMAL POWER to less than 50% of RATED THERMAL POWER within the next 2 hours and reduce the Power Range Neutron Flux-High Trip setpoints to less than or equal to 55% of RATED THERMAL POWER within the next 4hours.
See Special Test Exception 3.10.2.
SALEM - UNIT 2                        3/4 2-13

POWER DISTRIBUTION LIMITS LIMITING CONDITION FOR OPERATION (Continued) b)    Identify and correct the cause of the out of limit condi-tion prior to increasing THERMAL POWER; subsequent POWER OPERATION above 50% of RATED THERMAL power may proceed provided that the QUADRANT POWER TILT RATIO is verified within its limit at least once per hour for 12 hours or until verified acceptable at 95% or greater RATED THERMAL POWER.
: b. With the QUADRANT POWER TILT RATIO determined to exceed 1.09 due to misalignment of either a shutdown or control rod:
: 1. Calculate the QUADRANT POWER TILT RATIO at least once per hour until:
(a)   Either the QUADRANT POWER TILT RATIO is reduced to within its limit, or (b)   THERMAL POWER is reduced to less than 50% of RATED THERMAL POWER.
: 2. Reduce THERMAL POWER at least 3% from RATED THERMAL POWER for each 1% of indicated QUADRANT POWER TILT RATIO in excess of 1.0, within 30 minutes.
: 3. Verify that-the QUADRANT POWER TILT RATIO is within its limit within 2 hours after exceeding the limit or reduce THERMAL POWER to less than 50% of RATED THERMAL POWER within the next 2 hours and reduce the Power Range Neutron Flux-High Trip Setpoints to less than or equal to 55% of RATED THERMAL POWER within the next 4 hours.
: 4. Identify and correct the cause of the out of limit condition prior to increasing THERMAL POWER; subsequent POWER OPERATION above 50% of RATED THERMAL POWER may proceed provided that the QUADRANT POWER TILT RATIO is verified within its limit at least once per hour for 12 hours or until verified acceptable at 95%
or greater RATED THERMAL POWER.
: c. With the QUADRANT POWER TILT RATIO determined to exceed 1.09 due to causes other than the misalignment of either a shutdown or control.
rod:
SALEM - UNIT 2                        3/4 2-14

POWER DISTRIBUTION LIMITS LIMITING CONDITION FOR OPERATION (Continued)
: 1.      Calculate the QUADRANT POWER TILT RATIO at least once per hour until:
(a)     Either the QUADRANT POWER TILT RATIO is reduced to within its limit, or (b)     THERMAL POWER is reduced to less than 50% of RATED THERMAL POWER.
: 2.      Reduce THERMAL POWER to less than 50% of RATED THERMAL POWER within 2 hours and reduce the Power Range Neutron Flux-High Trip Setpoints to less than or equal to 55% of RATED THERMAL POWER within the next 4 hours.
: 3.      Identify and correct the cause of the out of limit condition prior to increasing THERMAL POWER; subsequent POWER OPERATION above 50% of RATED THERMAL POWER may proceed provided that the QUADRANT POWER TILT RATIO is verified within its limit at least once per hour for 12 hours or until verified at 95% or greater RATED THERMAL POWER.
SURVEILLANCE REQUIREMENTS 4.2.4.1 The QUADRANT POWER TILT RATIO shall be determined to be within the limit above 50% of RATED THERMAL POWER by:
: a.      Calculating the ratio in accordance with the Surveillance Frequency Control Program when the alarm is OPERABLE.
: b.      Calculating the ratio in accordance with the Surveillance Frequency Control Program during steady-state operation when the alarm is inoperable.
4.2.4.2 The QUADRANT POWER TILT RATIO shall be determined to be within the limit when above 75% of RATED THERMAL POWER with one Power Range Channel inoperable by obtaining a core power distribution measurement* to confirm that the normalized symmetric power distribution is consistent with the indicated QUADRANT POWER TILT RATIO in accordance with the Surveillance Frequency Control Program.
Using either the movable incore detectors in the four pairs of symmetric thimble locations or the power distribution monitoring system.
SALEM - UNIT 2                                 314 2-15                          Amendment No. 282

POWER DISTRIBUTION LIMITS 3/4.2.5 DNB PARAMETERS LIMITING CONDITLION FOR OPERATION 3.2.5 The following DNB related parameters shall be maintained within the limits shown on Table 3.2-1:
: a.      Reactor Coolant System Tavg.
: b.      Pressurizer Pressure.
: c.      Reactor Coolant System Total Flow Rate.
APPLICABILITY: MODE 1 ACTION:
With any of the above parameters exceeding its limit, restore the parameter to within its limit within 2 hours or reduce THERMAL POWER to less than 5% of RATED THERMAL POWER within the next 4 hours.
SURVEILLANCE REQUIREMENTS 4.2.5.1 Each of the parameters of Table 3.2-1 shall be verified to be within their limits in accordance with the Surveillance Frequency Control Program.
4.2.5.2 The Reactor Coolant System Total Flow Rate shall be determined to be within the limits of Table 3.2-1 by performing a precision heat balance within 24 hours after achieving steady state conditions a 90% RATED THERMAL POWER in accordance with the Surveillance Frequency Control Program. The provisions of Specification 4.0.4 are not applicable.
SALEM - UNIT 2                               314 2-16                        Amendment No. 282

TABLE 3.2-1 D-ND PARAM TERS 4 Loops in Reactor Coolant System T, s S82.9*7 I
Pressuri.zer Pressure a 2200 psia         I Reactor Coolant System Total Flow Rate                       a 341,000           I J -- it not aplic.able during either a THWE74ML POWlER ramp in excess of 5% RATrD T*ERMAL POWER per minute or a THEi*AL POWER step in excess of 10% RATED THERL POWER.
0  Zncludes a 2.4% flow uncertaintY*plus a 0.1% measurement due to feedwate* venturi fouling.
mncert8inty   I SALZK - UNIT 2                               3/4 2-1.7        Amendment No .197

3/4.3 INSTRUMENTATION 3/4.3.1 REACTOR TRIP SYSTEM INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.1.1 As a minimum, the reactor trip system instrumentation channels and interlocks of Table 3.3-1 shall be OPERABLE.
APPLICABILITY: As shown in Table 3.3-1.
ACTION:
As shown in Table 3.3-1.
SURVEILLANCE REQUIREMENTS 4.3.1.1.1 Each reactor trip system instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL CALIBRATION and CHANNEL FUNCTIONAL TEST operations at the frequencies specified in the Surveillance Frequency Control Program unless otherwise noted in Table 4.3-1.
4.3.1.1.2 The logic for the interlocks shall be demonstrated OPERABLE prior to each reactor startup unless performed during the preceding 92 days. The total interlock function shall be demonstrated OPERABLE in accordance with the Surveillance Frequency Control Program during CHANNEL CALIBRATION testing of each channel affected by interlock operation.
4.3.1.1.3 The REACTOR TRIP SYSTEM RESPONSE TIME of each reactor trip function shall be verified to be within its limit in accordance with the Surveillance Frequency Control Program.
Neutron detectors are exempt from response time testing.
SALEM - UNIT 2                                  3/4 3-1                       Amendment No. 282

TABLE 3.3-1 RE ACTOR TRIP SYSTEM INSTRUMENTATION MINIM1JM TrOTFAL NUMBER       CHANNELS     CHANNELS APPLICABLE FUNCTIONAL UNIT                      OF CHANNELS          TO TRIP      OPERABLE MODES             ACTION
 .. Manual Reactor Trip                    2                1             2    I, 2 and           12
: 2. Power Range,  Neutron Flux            4                2             3    1,2 and 3*           2
: 3. Power Range, Neutron Flux             4                2             3    1,2                  2 High Positive Rate
: 4. Deleted
: 5. Intermediate  Range, Neutron Flux     2                              2    1,2  and
* 3
: 6. Source Range,  Neutron Flux A. Startup                          2                              2    2##, and              4 B. Shutdown                         2                0              1   3,4 and 5            5 Overtemperature  AT                   4                2              3    1,2                  6
: 8. Overpower AT-                         4                2              3    1,2                  6
: 9. Pressurizer Pressure-Low               4                2             3    1,2                  6
: 10. Pressurizer Pressure--High             4                2             3    1,2                  6 SALEN - UNIT 2                                      3/4 3-2                       EAmendment No. 261

TABLE 3.3-1  (Continued)
REACTOR TRIP SYSTEM INSTRUMENTATION MINIMUM TOTAL.NUMBER         CHANNELS  CHANNELS      APPLICABLE FUNCTIONAL UNIT                            OF CHANNELS          TO TRIP   OPERABLE        MODES ACTION
: 11. Pressurizer Water Level--High            3                    2           2           1,  2       6
: 12. Loss of Flow -  Single Loop              3
                                                /loop         2/loop in   2/loop in        1           6 (Above P-8)                                             any oper-   each oper-ating loop  ating loop
: 13. Loss of Flow - Two Loops                 3/loop          2/loop in   2/loop in        1           6 (Above P-7 and below P-8)                               two oper-   each oper-ating loops ating loop
: 14. Steam Generator Water Level--            3
                                                /loop         2/loop in   2/loop in        1, 2        6 Low-Low                                                  any oper-   each oper-ating loops ating loop
: 15. Deleted
: 16. Undevoltage-Reactor Coolant Pumps        4-1/bus         1/2 twice   3                1           6
: 17. Underfrequency-Reactor  Coolant Pumps    4-1/bus         1/2 twice   3                1           6 SALEM - UNIT 2                                             3/4 3-3                   Amendment No. 258

TABLE 3.3-1   (Continued)
REACTOR TRIP SYSTEM INSTRUMENTATION MINIMUM TOTAL NUMBER     CHANNELS CHANNELS   APPLICABLE FUNCTIONAL UNIT                                  OF CHANNELS      TO TRIP  OPERABLE     MODES       ACTION
: 18. Turbine Trip
: a. Low Autostop Oil Pressure                     3             2          2         1            6
: b. Turbine Stop Valve Closure                    4             4          3         1            6
: 19. Safety Injection Input from ESF                  2              1         2          1,2          10
: 20. Reactor Coolant Pump Breaker                 1/breaker          2      I/breaker                  11 Position Trip (above P-7)                                              per opera-ting loop
: 21. Reactor Trip Breakers                            2                         2         1,2          1###, 14 1                    3*, 4*, 5*   13
: 22. Automatic Trip Logic                              2                        2         1,2          10 3", 4*, 5*   13 SALEM - UNIT 2                                          3/4 3-4                         Amendment No. 258

TABLE 3.3-1  (Continued)
TABLE NOTATION
* With the reactor trip system breakers in the closed position and the control rod drive system capable of rod withdrawal.
##    High voltage to detector may be de-energized above P-6.
S###  If ACTION Statement 1 is entered as a result of Reactor Trip Breaker (RTB) or Reactor Trip Bypass Breaker (RTBB) maintenance testing results exceeding the following acceptance criteria, NRC reporting shall be made within 30 days in accordance with Specification 6.9.2:
: 1. A RTB or RTBB trip failure during any surveillance test with less than or equal to 300 grams of weight added to the breaker trip bar.
: 2. A RTB or RTBB time response failure that results in the overall reactor trip system time response exceeding the Technical Specification limit.
ACTION STATEMENTS ACTION 1           With the number of channels OPERABLE one less than required by the Minimum Channels OPERABLE requirement, be in HOT STANDBY within 6 hours; however, one channel may be bypassed for up to 2 hours for surveillance testing per Specification 4.3.1.1.1 provided the other channel is OPERABLE, ACTION 2           With the number of OPERABLE channels one less than the Total Number of Channels, STARTUP and/or POWER OPERATION may proceed provided the following conditions are satisfied:
: a. The inoperable channel is   placed in the tripped condition within 6 hours.
: b. The Minimum Channels OPERABLE requirement is met; however, the inoperable channel may be bypassed for up to 4 hours for surveillance testing of other channels per Specification 4.3.1.1.1.
C. Either, THERMAL POWER is restricted to
* 75% of RATED THERMAL POWER and the Power Range, Neutron Flux trip setpoint is reduced to
* 85% of RATED THERMAL POWER within 4 hours; or, the QUADRANT POWER TILT RATIO is monitored at least once per 12 hours.
: d. The QUADRANT POWER TILT RATIO, as indicated by the remaining three detectors, is verified consistent with the normalized symmetric power distribution obtained by using either the movable in-core detectors in the four pairs of symmetric thimble locations or the power distribution monitoring system at least once per 12 hours when THERMAL POWER is greater than 75% of RATED THERMAL POWER.
SALEM - UNIT 2                           3/4 3-5              Amendment No. 258

by the Minimum Channels OPERABLE requirement and with the THERMAL POWER level:
: a. Below P-6, restore the inoperable channel to OPERABLE status prior to increasing THERMAL POWER above the P-6 Setpoint.
: b. Above P-6, but below 5% of RATED THERMAL POWER, restore the inoperable channel to OPERABLE status prior to increasing THERMAL POWER above 5% of RATED THERMAL POWER.
: c. Above 5% of RATED THERMAL POWER,  POWER OPERATION may continue.
: d. Above 10% of RATED THERMAL POWER, the provisions of Specification 3.0.3 are not applicable.
ACTION 4       With the number of channels OPERABLE one lose than required by the Minimum Channels OPERABLE requirement and with the THERMAL POWER level:
: a. Below P-6, restore the inoperable channel to OPERABLE status prior to increasing THERMAL POWER above the P-6 Setpoint.
: b. Above P-6, operation may continue.
ACTION 5       With the number of channels OPERABLE one less than required by the Minimum Channels OPERABLE requirement, verify compliance with the SHUTDOWN MARGIN requirements of Specification 3.1.1.1 or 3.1.1.2, an applicable, within 1 hour and at least once per 12 hours thereafter.
ACTION 6       With the number of OPERABLE channels one less than the Total Number of Channels, STARTUP and/or POWER OPERATION may proceed provided the following conditions are satisfied:
: a. The inoperable channel is placed in the tripped condition within 6 hours.
: b. The Minimum Channel OPERABLE requirement is met; however, the inoperable channel may be bypassed for up to 4 hours for surveillance testing of other channels per Specification 4.3.1.1.1.
ACTION 7  -    NOT USED ACTION 8  -    NOT USED ACTION 9  -    NOT USED SALEM - UNIT 2                        3/4 3-6                 SAmendment No. 121

TABLE 3.3-1 (Continued)
ACTION 10 -   With the number of OPERABLE Channels one less than the Minimum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 6 hours or be in at least HOT STANDBY in the next 6 hours; however, one channel may be bypassed for up to
              -4 hours for surveillance testing per Specification 4.3,.1.1 provided the other channel is OPERABLE.
ACTION 11 -   With less than the Minimum Number of Channels OPERABLE, operation may continue provided the inoperable channel is     placed in the tripped condition within 6 hours.
ACTION 12 -   With the number of channels OPERABLE one less than required by the Minimum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 48 hours or be in HOT STANDBY within the next 6 hours and/or open the reactor trip breakers.
ACTION 13 -   With the   number of OPERABLE channels one less than the Minimum Channels   OPERABLE requirement, restore the inoperable channel to OPERABLE   status within 48 hours or open the reactor trip breakers   within the next hour.
ACTION 14 -   With one of the diverse trip features (Undervoltage or shunt trip attachment) inoperable, restore it to OPERABLE status within 48 hours or declare the breaker inoperable and be in at least HOT STANDBY within 6 hours. The breaker shall not be bypassed while one of the diverse trip features is inoperable except for the time required for performing maintenance to restore the breaker to OPERABLE status.
REACTOR TRIP SYSTEM INTERLOCKS DESIGNATION'     CONDITION AND SETPOINT                 FUNCTION P-6              With 2 of 2 Intermediate Range         P-6 prevents or defeats Neutron Flux Channels < 6x10"          the manual block of source amps.                                  range reactor trip.
P-7              With 2 of 4 Power Range Neutron        P-7 prevents or defeats Flux Channels 2 11% of RATED           the automatic block of THERMAL POWER or 1 of 2 Turbine        reactor trip on- Low flow steam line inlet pressure channels     in more than one primary coolant loop, reactor
                 &#xfd; a pressure equivalent to 11% of coolant pump undervoltage RATED THE?.'AL POWER.
and under-frequency, pressurizer low pressure, pressurizer high level, and the opening of more than one reactor coolant pump breaker.
SALEM - UNIT 2                     3/4 3-7                        Amendment No,  240

DESIGNATION          CONDITION AND SETPOINT              FUNCTION P-8           With 2 of 4 Power Range Neutron P-8 prevents or defeats Flux channels &#x17d; 36% of RATED    the automatic block of THERMAL POWER.                  reactor trip on low coolant flow in a single loop.
P-9           With 2 of 4 Power range neutron  P-9 prevents or defeats flux channels &#x17d; 50% of RATED    the automatic block of THERMAL POWER.                   reactor trip on turbine trip.
With 3 of 4 Power range neutron  P-10 prevents or defeats flux channels < 9% of RATED     the manual block oft THERMAL POWER.                   Power range low setpoint reactor trip, Intermediate range reactor trip, and intermediate range rod stops.
Provides input to P-7.
0 SALEM - UNIT 2                       3/4 3-8                Amendment No. 58
                                                                              '4

Page Left Blank Intentionally SALEM - UNIT 2     3/4 3-9                   Amendment No. 266

Page Left Blank Intentionally I
SALEM - UNIT 2 3/4 3-10 Amendment No.
266

TABLE 4.3-1 REACTOR TRIP SYSTEM INSTRUMENTATION SLIRVEILLANCE REQUIREMENTS MODES IN CHANNEL            WHICH CHANNEL       CHANNEL      FUNCTIONAL      SURVEILLANCE FUN CTIONAL UNIT                CHECK"5"  CALIBRATION""5
* TEST""5)       REQUIRED
: 1. Nvanual Reactor Trip Switch    N.A.            N.A.           (9)           1, 2, and *
: 2. Plower Range, Neutron Flux                (2), (3) (6)                    1, 2, and 3*
: 3. Ppower Range, Neutron Flux,    N.A.             (6)                             1,2 High Positive Rate
: 4. Deleted
: 5. Intermediate Range, Neutron                    (6)                         1,2 and
* Flux
: 6. Source Range, Neutron Flux     (7)             (6)     (16) and S/Ut"   2, 3, 4, 5 and
: 7. Overtemperature AT                                                             1, 2
: 8. Overpower AT                                                                   1,2
: 9. Pressurizer Pressure--Low                                                      1,2
: 10. Pressurizer Pressure--High                                                     1,2
: 11. Pressurizer Water Level--                                                      1,2 High
: 12. Loss of Flow - Single Loop                                                       I SALEM - UNIT 2                           3/4 3-11                       Amendment No. 282

TABLE 4.3-1 (Continued)
REACTOR TRIP SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS MODES IN CHANNEL            WHICH CHANNEL        CHANNEL      FUNCTIONAL      SURVEILLANCE FLI N CTIONAL UNIT              CHECK(1 5) CALIBRATION""s)     TESTV1 5)      REQUIRED
: 13. Loss of Flow Two Loops                                       N.A.               1
: 14. SSteam Generator Water 1,2 Level--Low-Low
: 15. DELETED
: 16. Undervoltage - Reactor         N.A.                                             1 Coolant Pumps
: 17. Underfrequency - Reactor N.A.                                             1 Coolant Pumps
: 18. Turbine Trip
: a. Low Autostop Oil         N,A.            N.A.         S/U111             1,2 Pressure
: b. Turbine Stop Valve        N.A.            N.A.                            1,2 Closure
: 19. Safety Injection Input from    N.A.            N.A.         (4)(5)             1,2 ESF
: 20. Reactor Coolant Pump           N.A.            N.A.                             1 Breaker Position Trip
: 21. Reactor Trip Breaker           N.A.            N.A.    (5)(11)(13)(14)      1 2 and *
: 22. Automatic Trip Logic           N.A.            N.A.           (5)          1, 2 and
* SALEM - UNIT 2                            3/4 3-12                       Amendment No. 282

TABLE 4.3-1 (Continued)
NOTATION With the reactor trip system breakers.closed and the control rod drive system capable of rod withdrawal.
(1) -  If not performed in previous 31 days.
(2) -  Heat balance only, above 15% of RATED THERMAL POWER.
(3)-   Compare incore to excore axial offset above 15% of RATED THERMAL POWER.
Recalibrate if absolute difference ->3 percent.
(4) -  Manual SSPS functional input check in accordance with the Surveillance Frequency Control Program.
(5) -  Each train or logic channel shall be tested in accordance with the Surveillance Frequency Control Program.
(6) -  Neutron detectors may be excluded from CHANNEL CALIBRATION.
(7) -  Below P-6 (Block of Source Range Reactor Trip) setpoint.
(8) -  Deleted (9) -  The CHANNEL FUNCTIONAL TEST shall independently verify the OPERABILITY of the Undervoltage and Shunt Trip mechanism for the Manual Reactor Trip Function.
The Test shall also verify OPERABILITY of the Bypass Breaker Trip circuits.
(10)-  DELETED (11) - The CHANNEL FUNCTIONAL TEST shall independently verify the OPERABILITY of the Reactor Trip Breaker Undervoltage and Shunt Trip mechanisms.
(12)-  DELETED (13) - Verify operation of Bypass Breakers Shunt Trip function from local pushbutton while breaker is in the test position prior to placing breaker in service.
(14) - Perform a functional test of the Bypass Breakers U.V. Attachment via the SSPS.
(15)   Frequencies are specified in the Surveillance Frequency Control Program unless otherwise noted in the table.
(16)   At the frequency specified in the Surveillance Frequency Control Program, SALEM - UNIT 2                                 3/4 3-13                     Amendment No. 282

INSTRUMENTATION 3/4.3.2 ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.2.1 The Engineered Safety Feature Actuation System (ESFAS) instrumentation channels and interlocks shown in Table 3.3-3 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3-4.
APPLICABILITY: As shown in Table 3.3-3.
ACTION:
: a.       With an ESFAS instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3-4, declare the channel inoperable and apply the applicable ACTION requirement of Table 3.3-3 until the channel is restored to OPERABLE status with the trip setpoint adjusted consistent with the Trip Setpoint value.
: b.       With an ESFAS instrumentation channel inoperable, take the ACTION shown in Table 3.3-3.
SURVEILLANCE REQUIREMENTS 4.3.2.1.1 Each ESFAS instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL CALIBRATION and CHANNEL FUNCTIONAL TEST operations at frequencies specified in the Surveillance Frequency Control Program unless otherwise noted in Table 4.3-2.
4.3.2.1.2 The logic for the interlocks shall be demonstrated OPERABLE during the automatic actuation logic test. The total interlock function shall be demonstrated OPERABLE in accordance with the Surveillance Frequency Control Program during CHANNEL CALIBRATION testing of each channel affected by interlock operation.
4.3.2.1.3 The ENGINEERED SAFETY FEATURES RESPONSE TIME of each ESFAS function shall be verified to be within the limit in accordance with the Surveillance Frequency Control Program. The provisions of Specification 4.0.4 are not applicable to MSIV closure time testing.
The provisions of Specification 4.0.4 are not applicable to the turbine driven auxiliary feedwater pump provided the surveillance is performed within 24 hours after the secondary steam generator pressure is greater than 680 psig.
SALEM - UNIT 2                                  3/4 3-14                       Amendment No. 282

TABLE 3.3-3 ENGINEERED SAFETY FEATURE ACTUATION SYSTEM :NSTRUMENTATION MINIMUM TOTAL NO.          CHANNELS      CHANNELS        APPLICABLE FUNCTIONAL UNIT                                 OF CHANNELS        TO TRIP       OPERABLE          MODES       ACTION
: 1. SAFETY INJECTION, TURBINE TRIP AND FEEDWATER ISOLATION
: a. Manual Initiation                       2                                    2          1,2,3,4         18
: b. Automatic Actuation Logic               2                                    2          1,2,3,4         13
: c. Containment Pressure-High              3                   2                2          1,2,3           19
: d. Pressurizer Pressure-Low               3                   2                2          1,2,3#          19
: e. Differential Pressure Between         3/steam line       2/steam line     2/steam       1,2,3##         19 Steam Lines    - High                                   any steam        line lines
: f. Steam Flow in Two Steam Lines-High 2/steam line       1/steam line any 2 steam 1/steam line 1,2,3##         19   I lines COINCIDENT WITH EITHER Tavg -- Low-Low                       1 Tavg/loop        1 Tavg in any 2 loops 1 Tavg in any 1,2,3##         19   I 3 loops OR, COINCIDENT WITH Steam Line Pressure-Low               1 pressure/
loop 1 pressure any 2 loops 1 pressure any 3 loops 1,2,3##         19   I SALEM - UNIT 2                                               3/4 3-15                                Amendment No. 258

This page is intentionally left blank.
SALEM - UNIT 2                3/4 3-16            Amendment No. 116

TABLE 3.3-3 (Continued)
ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION MINIMUM TOTAL NO.       CHANNELS      CHANNELS    APPLICABLE FUNCTIONAL UNIT                            OF CHANNELS     TO TRIP      OPERABLE       MODES    ACTION
: 2. CONTAINMENT SPRAY
: a. Manual                             2 sets of 2      I set of 2   2 sets of 2 1,2,3,4      18
: b. Automatic Actuation Logic                2              1            2       1,2,3,4      13
: c. Containment Pressure--High-High          4              2            3       1,2,3        16
: 3. CONTAINMENT ISOLATION
: a. Phase "A" Isolation Manual                                              1            2       1,2,3,4      18
: 1)                                       2 2              1            2       1,2,3,4      13
: 2)  From Safety Injection Automatic Actuation Logic S

6                                                       4 MAItLE 3.3-3 (Continued)
ENGINIER(l  SAFETY F[ArtPRi    ACTUATION SYSIEN INSRUH[ENIATION I                                                                                     HI NI"HU1 TOJAL NO.              CHANNELS           CHANNELS   APPL ICAHLE (F CHANNELS               10 TRIP            OPERABLE       14011L S
.9   FUNCTIONAL UNIT
: h. Phase "* IsolatioIn I set of 2                     1. 2, 3, 4 3I) "anual                  2 sets of 2                                 2 sets of 2 2                        I                   2    1, 2. 3. 4
: 2)   Automatic Actuation Logic 1 2,      3
: 3)  Containwent                  4                                            3 Pressure--High-High
: c. Containment Ventilation Isolation I2.       3. 4 2                        I                   2 I.'           3) manual S                                                                                               1,2. 3, 4 I-i                                            2                                            2 m             2)  Automatic Actuation                                   I Logic per table 3.3-6
: 9)  Containment Atmo-sphere Iaseous Radioactivity-High I
: 3.                                                                                                         I rt 0

TABLE 3.3-3    (Continued)
ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION MINIMUM TOTAL NO.           CHANNELS          CHANNELS     APPLICABLE FUNCTIONAL UNIT                          OF CHANNELS         TO TRIP           OPERABLE       MODES        ACTION
: 4. STEAM LINE ISOLATION
: a. Manual                          2/steam line     1/steam line         !/operating    1,2,3            23 steam line
: b. Automatic Actuation Logic                2*W            1                 2          1,2,3            20 4 *2
: c. Containment Pressure--                                                    3          1,2,3            16 High-High
: d. Steam Flow in Two               2/steam line      1/steam line        1/steam line   1,2, 3##         19 Steam Lines--High                                 any 2 steam lines COINCIDENT WITH EITHER Taug--Low-Low                   1 T,,g/loop      1 TaVg in           1 Tav, in      1,2, 3##         19 any 2 loops         any 3 loops OR, COINCIDENT WITH Steam Line Pressure-Low        1 pressure/       1 pressure           1 pressure     1, 2, 3##       19 loop              any 2 loops         any 3 loops SALEM -  UNIT 2                                          3/4 3-19                                Amendment No. 258

                                          -TABLE 3.3-3   (Continued)
ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION MINIMUM TOTAL NO.        CHANNELS      CHANNELS        APPLICABLE FUNCTIONAL UNIT                        OF CHANNELS      TO TRIP       OPERABLE          MODES        ACTION
: 5. TURBINE TRIP @ FEEDWATER ISOLATION
    .a. Steam Generator Water level--High-High 3/loop         2/loop in any operating 2/loop in each operating 1,2,3           19 I
loop            loop
: 6. SAFEGUARDS EQUIPMENT CONTROL           3              2               3           1,2,3,4         13 SYSTEM (SEC)
: 7. UNDERVOLTAGE, VITAL BUS
: a. Loss of Voltage                l/bus              2               3           1,2,3           14
: b. Sustained Degraded Voltage     3/bus          2/bus            3/bus          1,2,3           14 SALEM - UNIT 2                                       3/4 3-20                               Amendment No. 258

TABLE 3.3-3  (Continued)
ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION MINIMUM TOTAL NO.         CHANNELS            CHANNELS          APPLICABLE FUNCTIONAL UNIT                           OF CHANNELS       TO TRIP             OPERABLE             MODES      ACTION
: 8. AUXILIARY FEEDWATER
: a. Automatic Actuation Logic **          2                 1                    2          1,2,3           20
: b. NOT USED
: c. Stm. Gen. Water Level-Low-Low
: z. Start Motor Driven Pumps     3/stm. gen.       2/stm. gen.          2/stm. gen.      1,2,3         19 any stm. gen.
ii. Start Turbine Driven Pumps   3/stm. gen.      2/stm. gen.          2/stm. gen.      1,2,3         19 any 2 stm.gen.
: d. Undervoltage - RCP Start          4-1/bus           1/2 x 2              3              1,2             19 Turbine - Driven Pump
: e. S.I. Start Motor-Driven Pumps          See 1 above   (All S.I. initiating     functions and requirements)
: f. Trip of Main Feedwater Pumps      2/pump            1/pump              1/pump          1,2             21 Start Motor-Driven Pumps
: g. Station Blackout                        See 6 and 7 above   (SEC and UV Vital Bus)
: 9. SEMIAUTOMATIC TRANSFER TO RECIRCULATION
: a. RWST Level Low                    4                  2                   3              1,2,3           16
: b. Automatic Actuation Logic         2                  1                   2              1,2,3           20 SALEM -   UNIT 2                                          3/4 3-21                                     Amendment No. 258

TABLE 3.3-3  (Continued)
TABLE NOTATION
#4      Trip function may be bypassed in this MODE below P-l1.
Trip function may be bypassed in this MODE below P-12.
**     Applies to Functional Unit 8 items c and d.
***     The automatic actuation logic includes two redundant solenoid operated vent valves for each Main Steam Isolation Valve. One vent valve on any one Main Steam Isolation Valve may be isolated without affecting the function of the automatic actuation logic provided the remaining seven solenoid vent valves
:remain OPERABLE. The isolated MSIV vent valve shall be returned to OPERABLE status upon the first  entry into MODE 5 following determination that the vent valve is inoperable. For any condition where more than one of the eight solenoid vent valves are inoperable, entry into ACTION 20 is required.
ACTION STATEMENTS ACTION 13   - With the number of OPERABLE Channels one less than the Total Number of Channels, restore the inoperable channel to OPERABLE status within 6 hours or, be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours; however, one channel may be bypassed for up to 4 hours for surveillance testing per Specification 4.3.2.1.1 provided the other channel is OPERABLE.
ACTION 14   - With the number of OPERABLE Channels one less than the Total Number of Channels, operation may proceed until performance of the next required CHANNEL FUNCTIONAL TEST, provided the inoperable channel is placed in the tripped condition within 1 hour.
ACTION 15 -   NOT USED ACTION 16 - With the number of OPERABLE Channels one less than the Total Number of Channels, operation may proceed provided the inoperable channel is placed in the bypassed condition and the Minimum Channels OPERABLE requirement is demonstrated by CHANNEL CHECK within 6 hours; one additional channel may be bypassed for up to 4 hours for surveillance testing per Specification 4.3.2.1.1.
ACTION 17 -   With less than the Minimum Channels OPERABLE, operation may continue provided the containment purge and exhaust valves are maintained closed.
ACTION 18 - Wit h the number of OPERABLE Channels one less than the Total Number of Channels, restore the inoperable channel to OPERABLE status within 48 hours or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
SALEM - UNIT 2                           3/4 3-22                       Amendment No. 258

TABLE 3.3-3 (Continued)
ACTION 19 -    With the number of OPERABLE Channels one less than the Total Number of Channels, STARTUP and/or POWER OPERATION may proceed provided the following conditions are satisfied:
: a. The inoperable channel is  placed in the tripped condition within 6 hours.
: b. The Minimum Channels OPERABLE requirements is met; However, the inoperable channel may be bypassed for up to 4 hours for surveillance testing of other channels per Specification 4.3.2.1.1.
ACTION 20 -    With the number of OPERABLE Channels one less than the Total Number of Channels, restore the inoperable channel to operable status within 6 hours or, be in at least HOT STANDBY within the next 6 hours and in at least HOT SHUTDOWN within the following 6 hours; however, one channel may be bypassed for up to 4 hours for surveillance testing per Specification 4.3.2.1.1 provided the other channel in OPERABLE.
ACTION 21 -    With the number of OPERABLE channels one less than the Minimum Number of Channels, operation may proceed provided that the I
inoperable channel is restored to OPERABLE within 72 hours.
ACTION 22 -    NOT USED ACTION 23 -    With the number of OPERABLE Channels one less than the Total Number of Channels, restore the inoperable channel to OPERABLE status within 48 hours or be in at least HOT STANDBY within 6 hours and in HOT SHUTDOWN within the following 6 hours.
0 3/4 3-23 SALEM - UNIT 2                                               Amendment No. 174 I

TABLE 3.3-3  (Continued)
ENGINEERED SAFETY FEATURES    INTERLOCKS DESIGNATION    CONDITION AND SETPOINT               FUNCTION P-1l           With 2 of 3 pressurizer              P-li prevents or defeats pressure channels                    manual block of safety a 1925 psig.                         injection actuation on low pressurizer pressure.
P-12           With 3 of 4 Tavg channels            P-12 prevents or defeats at a setpoint of 5436F and           manual block of safety
                .u increasing                       injection actuation high (with an allowable setpoint          steam line flow and low value s545 0 F)                      steam line pressure.
With 2 of 4 Tavg channels            Allows manual block of at a setpoint of 543 0 F and         safety injection actuation T., decreasing                       on high steam line flow and (with an allowable setpoint         low steam line pressure.
value k5416F)                        Causes steam line isolation on high steam flow. Affects steam dump blocks.
SALEM - UNIT 2                         3/4 3-23a                 Amendment No.1 6 7 I

TABLE 3.3-4 ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION TRIP SETPOINTS FUNCTIONAL UNIT                               TRIP SETPOINT                    ALLOWABLE VALUES
: 1. SAFETY INJECTION, TURBINE TRIP AND FEEDWATER ISOLATION
: a. Manual Initiation                    Not Applicable                   Not Applicable
: b. Automatic Actuation Logic           Not Applicable                    Not Applicable
: c. Containment Pressure--High           : 4.0 psig                       , 4.5 psig
: d. Pressurizer Pressure--Low            2 1765 psig                      2 1755 psig
: e. Differential Pressure Between          100 psi                             112 psi Steam Lines--High
: f. Steam Flow in Two Steam Lines--      ! A function defined as
* A function defined as High Coincident with T ,,--Low-Low  follows: A Ap corresponding       follows: A Ap corresponding or Steam Line Pressure--Low         to 40% of full steam flow         to 44% of full steam flow between 0% and 20% load           between 0% and 20% load and and then a Ap increasing          then a Ap increasing linearly linearly to a Ap correspond-      to a Ap corresponding to ing to 110% of full steam         111.5% of full steam flow at flow at full load                 full    load 0                      Tavg   2 541OF Tavg 2 543   F z 600 psig steam line             2 579 psig steam line pressure                          pressure SALEM - UNIT 2                                       3/4 3-24                                 Amendment No. 170

0 (a
MADLA--4 'Cotnkunedl
                                                      !4~ ACYDA? IOW slaTin IEIThjfl~?p1b1I 3MIP   TDOIU?
: 2. 4C3UAXIGMT 8,31*
: a. Warnual Xnttat~en                          Not ApplLcable            Not ApplLcable
: b. Automatic Actuation Logic                    Hot Applicable           not AppliLable
: c. Conltainment ftessure--Ulb-UlLgh             !C 15.0 p*ig              K 16.0 peig I
: 3. COWTAIMMUSI~      SOLATZIO w            a. Fttams OA    Isolat ion
: 1. Naiwal                                 Not A"plicable            Not ApplLcable Gd S
w                  2. From Aafety InjectiLon                 Not app1icable             fot Appl Lcable Iautomatic Actuaationt Lo2ic:
: b. Phase    BS  Isolation
: 1. lMWOwal                                Not ApplMC&ble            Not Applicable
: 2. Automatic Actuation WOOi                 Not applcaable            Not Applicable eb 35.0 peig              ! 16.0 paig I
c.ConauanwA~t. ventilation, laoI~t ion II                .1. Nanual                                 Not AWlicable             Not AppL icablo
: 2. automatic Aotuatiou Logic              Not Applicable            Nat AppLicable It 0
I-
        -'a.

CA                                                              LU~LS 3.3-4 1~t~tln~edI Oaw-MmWOMmf,   MAflmO"   WwufffsrI   aq~~3a~Ig~  mV~~U  ~               quin AN9~139*
Ps IMIP    MOM=
-4 N)
: 3. Oontalmim      -qer                                              Per Table 3.3-6 GeenoU. NOAGOTLIty
: 4. STUN1 LIMB I3C5A120OE s.KBmOL                                                not Applicable                      not Applicable b.Autembtle Ac"tuat          10021.6~               not applicable                      mot Applicable C ontaimm~et Ite..ur.e-UtghMLgh                      AC 15.0 paig                         a 16.0 psig
: d. stge flew is Tom stem Line--                         !ca funottow def LOWd so             A Ia rnation define As itI                                                              follovis A Ap, earrrnpomdag          tollomat A A@ @@trmepondng Nigh Caimoldeat with
               ?Avg   -- Lo-Lt'     cur                          to 406 of full etsm Clo             to 440 of 94ll estag glow Stem Lim lrreemve          -     Low              betwees @3%   and 2ft load anid     between 0% MWd 28% 1.4ad And then a AV ieorsuaag ILUaseLY         theet a AV kuacreasig lisearty to -a Ap oorresaflniifl to           to a AV correponding to 110 of full stemn flow at           121.5% of ftll st~eas flow at f all load.                          full load.
T .,g 2: 54301 a: 600 POLO Stem Ilme                2t 67 psig atom JLLOO Preramote                           PC 85 - e 1'
S  5. Iu33U        TRIP no- 13U  =I       13RSW.TIOU 3
S                                                                   671 of narrow rn4*e
            *. t4"m Genertor water Level          -                                                S66" of narrow range S                                                              instrument armans
* at*m        instrusiet opan ech f8sh-Nioh                                        generator                            *team generator
 )
Not Applicable                      not Applicable N  6.* SAVSBIIARDS IQO IPIKIT CONVOWL SYSTEM
        'EEC' A

0 TABLE 3.3-4 ENGINEERED SAFETY FEA' [URE ACTUATION SYSTEM INSTRUMENTATION TRIP SETPOINTS FUNCTIONAL UNIT                                      TRIP SETPOINT                    AL]LOWABLE VALUES
: 7.      UNDERVOLTAGE,   VITAL BUS
: a. Loss of Voltage                       2 70% of bus voltage             2 65% of bus voltage
: b. Sustained Degraded Voltage            >  94.6% of bus voltage for       _  )4% of bus voltage for
                                                     *13 seconds                      :   L5 seconds
: 8.      AUXILIARY FEEDWATER
: a. Automatic Actuation Logic             Not Applicable                   Nolt Applicable
: b. NOT USED
: c. Steam Generator Water Level--
Low-Low
                                                     > 14.0% of narrow range instrument span each
                                                                                      > 13.0% of narrow range instrument span ea ch I
steam generator                   steam generator
: d. Undervoltage - RCP                    > 70% RCP bus voltage             2 65% RCP bus volt age
: e. S.I.                                  See 1 above (all S.I. setpoints)
: f. Trip of Main Feedwater Pump           Not Applicable                   Not Applicable
: g. Station Blackout                      See 6 and 7 above (SEC and Undervoltage,   Vital Bus)
: 9.      SEMIAUTOMATIC TRANSFER TO RECIRCULATION
: a. RWST Low Level                        15.25 tt. above                   15.25 + 1 ft. above Instrument taps                   instrument taps
: b. Automatic Actuation Logic             Not Applicable                   Not Applicable SALEM -    UNIT 2                                    3/4 3-27                             Amendment No. 238

Page Left Blank Intentionally                   I SALEM - UNIT 2             3/4 3-28          Amendment No. 266

Page Left Blank Intentionally I
SALEM - UNIT 2 3/4 3-29 Amendment No. 266

Page Left Blank Intentionally                   I SALEM - UNIT 2            3/4 3-30           Amendment No. 266

Page Left Blank Intentionally                   I SALEM - UNIT 2        3/4 3-31               Amendment No. 266

Page Left Blank Intentionally                   I SALEM - UNIT 2                3/4 3-32       Amendment No. 266

TABLE 4.3-2 ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS MODES IN CHANNEL          WHICH CHANNEL         CHANNEL     FUNCTIONAL     SURVEILLANCE 7
FUNCTIONAL UNIT                   CHECKC '    CALIBRATION(7)   TESTf 7 )      REQUIRED
: 1. SAFETY INJECTION, TURBINE TRIP AND FEEDWATER ISOLATION
: a. Manual Initiation             N.A.            N.A.                        1,2,3,4
: b. Automatic Actuation Logic     N.A.            N.A.         (2)            1,2,3,4
: c. Containment Pressure--                                     (3)             1,2,3 High
: d. Pressurizer Pressure--Low                                                  1,2,3
: e. Differential Pressure                                                      1,2,3 Between Steam Lines--
High
: f. Steam Flow in Two Steam                                                    1,2,3 Lines--High Coincident with Tavg--Low-Low or Steam Line Pressure--
Low
: 2. CONTAINMENT SPRAY
: a. Manual Initiation             N.A.            N.A.                        1,2,3,4
: b. Automatic Actuation Logic     N.A.            N.A.         (2)            1,2,3,4
: c. Containment Pressure--                                     (3)             1,2,3 High-High SALEM - UNIT 2                             3/4 3-33                      Amendment No. 282

TABLE 4.3-2 (Continued)
ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS MODES IN CHANNEL           WHICH CHANNEL         CHANNEL       FUNCTIONAL      SURVEILLANCE FUNCTIONAL UNIT                     CHECK"7 '   CALIBRATION"7 '      TEST"7 )      REQUIRED
: 3. CONTAINMENT ISOLATION
: a. Phase "A" Isolation
: 1) Manual                       N.A.            N.A.                           1,2,3,4
: 2)   From Safety Injection      N.A.            N.A.             (2)           1,2,3,4 Automatic Actuation Logic
: b. Phase "B" Isolation
: 1) Manual                       N.A.            N.A.                           1,2,3,4
: 2)  Automatic Actuation         N.A.            N.A.             (2)           1,2,3,4 Logic
: 3) Containment Pressure-                                         (3)            1,2,3
          -High-High
: c. Containment Ventilation Isolation
: 1) Manual                       N.A.            N.A.                           1,2,3,4
: 2)  Automatic Actuation         N.A.            N.A.             (2)           1,2,3,4 Logic
: 3)  Containment                   Per Surveillance Requirement 4.3.3.1 Atmosphere Gaseous Radioactivity- High SALEM - UNIT 2                               3/4 3-34                         Amendment No. 282

TABLE 4.3-2 (Continued)
ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS MODES IN CHANNEL        WHICH CHANNEL        CHANNEL     FUNCTIONAL    SURVEILLANCE FUNCTIONAL UNIT                    CHECK"'    CALIBRATION"7'    TEST(7"      REQUIRED
: 4. STEAM LINE ISOLATION
: a. Manual                        NA.            N.A.                       1,2,3**
: b. Automatic Actuation Logic      N.A.           N.A.          (2)           1,2,3
: c. Containment Pressure--                                     (3)           1,2,3 High-High cl. Steam Flow in Two Steam                                                  1,2,3 Lines--High Coincident with Tavg--Low-Low or Steam Line Pressure--
Low
: 5. TURBINE TRIP AND FEEDWATER ISOLATION
: a. Steam Generator Water                                                     1,2,3 Level--High-High
: 6. SAFEGUARDS EQUIPMENT CONTROL SYSTEM (SEC)
LOGIC
: a. Inputs                        N.A.           N.A.          (6)          1,2,3,4
: b. Logic, Timing and Outputs     N.A.           N.A.          (1)          1,2,3,4
: 7. UNDERVOLTAGE, VITAL BUS
: a. Loss of Voltage                                                          1,2,3
: b. Sustained Degraded                                                       1,2,3 Voltage SALEM - UNIT 2                             3/4 3-35                     Amendment No. 282

TABLE 4.3-2 (Continued)
ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS MODES IN CHANNEL         WHICH CHANNEL          CHANNEL          FUNCTIONAL     SURVEILLANCE FUNCTIONAL UNIT                      CHECK"7 '    CALIBRATION"7 )        TEST17)       REQUIRED
: 8. AUXILIARY FEEDWATER
: a. Automatic Actuation Logic        N.A.             N.A.                (2)           1,2,3
: b. NOT USED
: c. Steam Generator Water                                                               1,2,3 Level--Low-Low
: d. Undervoltage - RCP                                                                   1,2
: e. S.I.                          See 1 above (All S.I. surveillance requirements)
: f. Trip of Main Feedwater           N.A.             N.A.              S/U(4)           1,2 Pumps
: g. Station Blackout              See 6 and 7 above (SEC and UN Vital Bus)
: 9. SEMIAUTOMATIC TRANSFER TO RECIRCULATION
: a. RWST Low Level                                                                      1,2,3
: b. Automatic Initiation Logic       N.A.             N.A.                (2)          1,2,3,4 SALEM - UNIT 2                                 3/4 3-36                          Amendment No. 282

TABLE 4.3-2 (Continued)
TABLE NOTATION Outputs are up to, but not including, the Output Relays.
**   The provisions of Specification of 4.0.4 are not applicable.
(1)  Each logic channel shall be tested in accordance with the Surveillance Frequency Control Program. The CHANNEL FUNCTION TEST of each logic channel shall verify that its associated diesel generator automatic load sequence timer is OPERABLE with the interval between each load block within 1 second of its design interval.
(2)  Each train or logic channel shall be tested in accordance with the Surveillance Frequency Control Program.
(3)  The CHANNEL FUNCTIONAL TEST shall include exercising the transmitter by applying either a vacuum or pressure to the appropriate side of the transmitter.
(4)  If not performed in the previous 92 days.
(5)  NOT USED (6)  Inputs from undervoltage, Vital Bus, shall be tested in accordance with the Surveillance Frequency Control Program. Inputs from Solid State Protection System, shall be tested in accordance with the Surveillance Frequency Control Program.
(7)  Frequencies are specified in the Surveillance Frequency Control Program unless otherwise noted in the table.
SALEM - UNIT 2                              3/4 3-37                      Amendment No. 282

INSTRUMENTATION 3/4.3.3 MONITORING INSTRUMENTATION RADIATION MONITORING INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.3.1 The radiation monitoring instrumentation channels shown in Table 3.3-6 shall be OPERABLE with their alarm/trip setpoints within the specified limits.
APPLICABILITY: As shown in Table 3.3-6.
ACTION:
: a. With a radiation monitoring channel alarm/trip setpoint exceeding the value shown in Table 3.3-6, adjust the setpoint to within the limit within 4 hours or declare the channel inoperable.
: b. With one or more radiation monitoring channels inoperable, take the ACTION shown in Table 3.3-6.
: c. The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REQUIREMENTS 4.3.3.1 Each radiation monitoring instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, SOURCE CHECK, CHANNEL CALIBRATION and CHANNEL FUNCTIONAL TEST operations in accordance with the Surveillance Frequency Control Program.
SALEM - UNIT 2                              3/4 3-38                          Amendment No. 282

TABLE 3.3-6 RADIATION MONITORING INSTRUMENTATION MINIMUM CHANNELS      APPLICABLE           ALARM/TRIP                   MEASUREMENT INSTRUMENT                     OPERABLE        MODES                 SETPOINT                  RANGE           ACTION
: 1. AREA MONITORS
: a. Fuel Storage Area      I              *
                                                                        *15 mR/hr               10-1-10'  mR/hr    23
: 2. PROCESS MONITORS
: a. Containment
: 1) Gaseous Activity a)  Purge & Pressure              1, 2, 3, 4&5           per ODCM               101-106   cpm          26 Vacuum Relief                                       Control 3.3.3.9 Isolation 10 1-106 cpm b)  RCS Leakage         1         1,2, 3&4                   N/A                                       24 Detection
: 2) Air Particulate Activity a)  (NOT USED) b)  RCS Leakage         I         1,2, 3&4                   N/A                101-10 6 cpm           24 Detection
* With fuel in the storage pool or building.
The plant vent noble gas monitor may also function in        this     capacity when the purge/pressure-vacuum relief    isolation valves are open.
SALEM - UNIT 2                                                3/4 3-39                                  Amendment No. 253

TABLE 3.3-6 (Continued)
RADIATION MONITORING INSTRUMENTATION INSTRUMENT                                      MINIMUM      APPLICABLE         ALARM/TRIP       MEASUREMENT       ACTION CHANNELS         MODES             SETPOINT            RANGE OPERABLE
: 2. PROCESS MONITORS
: b. Noble Gas Effluent Monitors 3                 3
: 1) Medium Range Auxiliary Building             1          1,2,3&4      < 3.0x10-2 pCi/cm   10-3_101 pCi/cm      26 Exhaust System (Plant Vent)                                           (Alarm only) 2       3                 3
: 2) High Range Auxiliary Building               1          1,2,3&4      < 1.0x10 pCi/cm     10-110 pCi/cm       26 Exhaust System (Plant Vent)                                            (Alarm only)
: 3) Condenser Exhaust System                   1           1,2,3&4        -<7.12x10 4 cpm       1_106 cpm       26 (Alarm only)
: 3. CONTROL ROOM
: a. Air Intake - Radiation Level             2/Intake##          **
                                                                               < 2.48xl03 cpm       101-10 7 cpm     27,28
##-Control Room air intakes shared between Unit 1 and 2.
ALL MODES and during movement of irradiated fuel assemblies and during CORE ALTERATIONS.
SALEM - UNIT 2                                           3/4 3-39a                                        Amendment No. 278

TABLE 3.3-6 (Continued)
TABLE NOTATION ACTION 23 -  With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, perform area surveys of the monitored area with portable monitoring instrumentation at least once per 24 hours.
ACTION 24 -  With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, comply with the ACTION requirements of Specification 3.4.7.1.
ACTION 25-    (Not Used)
ACTION 26 -   With the number of OPERABLE Channels less than required by the Minimum Channels OPERABLE requirements, initiate the preplanned alternate method of monitoring the appropriate parameter(s), within 72 hours, and:
: 1)        either restore the irioperable Channel(s) to OPERABLE status within 7 days of the event, or
: 2)        prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within 14 days following the event outlining the action taken, the cause of the inoperability and the plans and schedule for restoring the system to OPERABLE status.
ACTION 27 -   With the number of channels OPERABLE one less than required by the Minimum Channels OPERABLE requirement, restore the inoperable channel(s) to OPERABLE status within 7 days or Initiate and maintain operation of the Control Room Emergency Air Conditioning System (CREACS) In the pressurization or recirculatlon mode of operation. CORE ALTERATIONS and movement of Irradiated fuel assemblies will be suspended during operation in the recirculation mode.
ACTION 28 -    With no channels OPERABLE In a Control Room air intake, Immediately initiate and maintain operation of the CREACS in the pressurization or recirculation mode of operation. CORE ALTERATIONS and movement of irradiated fuel assemblies will be suspended during operation in the recirculation mode.
SALEM - UNIT 2                            3/4 3-40                                         Amendment No. 245

TABLE 4.3-3 DELETED Page 3/4 3-42 Deleted SALEM - UNIT 2       3/4 3-41        Amendment No. 282

INSTRUMENTATION REMOTE SHUTDOWN INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.3.5 The remote shutdown monitoring instrumentation channels shown in Table 3.3-9 shall be OPERABLE with readouts displayed external to the control room.
APPLICABILITY: MODES 1, 2 and 3.
ACTION:
: a. With the number of OPERABLE remote shutdown monitoring channels less than required by Table 3.3-9, restore the inoperable channel to OPERABLE status within 7 days or be in HOT SHUTDOWN within the next 12 hours.
SURVEILLANCE REQUIREMENTS 4.3.3.5 Each remote shutdown monitoring instrumentation channel shall be demonstrated OPERABLE by performance of the CHANNEL CHECK, and CHANNEL CALIBRATION operations in accordance with the Surveillance Frequency Control Program.
SALEM - UNIT 2                               3/4 3-43                      Amendment No. 282

f-n                                                  TABLE 3.3-9 I-REMOTE SHUTDOWN MONITORING INSTRUMENTATION C
MINIMUM I-.
READOUT              MEASUREMENT          CHANNELS
-I INSTRUMENT                             LOCATION                RANGE             OPERABLE
: 1. Pressurizer Pressure       Hot Shutdown Panel 213       1700-2500 psig 1
: 2. Pressurizer Level        Hot-Shutdown Panel 213        0 - 100%
: 3. Steam Generator Pressure Hot Shutdown Panel 213        0 - 1200 psig 1/steam generator
: 4. Steam Generator Level    Hot Shutdown Panel 213        0 - 100%      1/steam generator CA~
CA) 0                                                 9

TABLE 4.3-6 DELETED SALEM - UNIT 2   3/4 3-45  Amendment No. 282

PMW 3/4 3-46 T IMM-3/4 3-49 ARE f lhlU y mA!U SANN - UNIT 2          3/4 3-46 throagh 3-49             1 No. 117 I

Gil (/&#xfd; (I

INSTRUMENTATION ACCIDENT MONITORING INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.3.7 The accident monitoring instrumentation channels shown in Table 3.3-11 shall be operable.
APPLICABILITY: MODES 1, 2, and 3.
ACTION:
: a. As shown in Table 3.3-11.
SURVEILLANCE REQUIREMENTS 4.3.3.7 Each accident monitoring instrumentation channel shall be demonstrated OPERABLE by performance of the CHANNEL CHECK, CHANNEL CALIBRATION and CHANNEL FUNCTIONAL TEST operations at the frequencies specified in the Surveillance Frequency Control Program unless otherwise noted in Table 4.3-11.
SALEM - UNIT 2                             3/4 3-50                      Amendment No. 282

TABLE 3.3-11 ACCIDENT MONITORING INSTRUMENTATION REQUIRED                 MINIMUM NO. OF                    NO. OF INSTRUMENT                                       CHANNELS                 CHANNELS                 ACTION
: 1. Reactor Coolant Outlet Temperatu3                2                         1                     1,    2 TnoT (Wide Range)
: 2. Reactor Coolant Inlet Temperaturf                2                         1                      1,    2 Tow (Wide Range)
: 3. Reactor Coolant Pressure (Wide R-ange)           2                          1                     1,    2
: 4. Pressurizer Water Level                                                                          1,     2 2                          1
: 5. Steam Line Pressure                         2/Steam Generator         1/Steam Generator           1,    2
: 6. Steam Generator Water Level (Nar:row        2/Steam Generator         1/Steam Generator           1,    2 Range)
: 7. Steam Generator Water Level Range)
(WidoB          4(1/Steam Generator)    3   (I/Steam Generator)    1,     2   I
: 8. Refueling Water Storage Tank Wat er         2                         1                           1,    2 Level
: 9. deleted
: 10. Auxiliary Feedwater Flow Rate                4  (i/Steem Generator)    3 (1/Steam Generator)       4,    6
: 11. Reactor Coolant System Subcoolin g          2                         1                           1,    2 Margin Monitor
: 12. PORV Position Indicator                      2/valve**                                             1,   2 SALEM - UNIT 2                                    3/4 3-51                             Amendment No. 206

TABLE 3.3-11   (Continued)
ACCIDENT MONITORING INSTRUMENTATION REQUIRED                MINIMUM NO. OF                  NO. OF INSTRUMENT                                                            CHANNELS                CHANNELS                  ACTION
: 13. PORV Block Valve           Position       Indicator                     4 2/valve*                    1                     1, 2
: 14. Pressurizer       Safety Valve           Position                2/valve**                   1                     1, 2 Indicator
: 15. Containment       Pressure        -   Narrow      Range          2                            1                    1, 2
: 16. Containment Pressure              -   Wide Range                 2                           1                     7, 2
: 17. Containment Water           Level -       Wide      Range        2                            1                    7, 2
: 18. Core      Exit Thermocouples                                     4/core quadrant             2/core quadrant       1, 2
: 19. Reactor Vessel         Level      Instrumentation                2                           1                     8, 9 System (RVLIS)
: 20. Containment High Range Accident                                  2                           2                     10 Radiation Monitor
: 21. Main       Steamline                                            1/                         I/                     10 Discharge (Safety                                           MS Line                    MS Line Valves and Atmospheric Steam Dumps) Monitor
(**) Total number of channels is considered to be two (2) with one (1) of the channels being any one (1) of the following alternate means of determining PORV, PORV Block, or Safety Valve position:                          Tailpipe Temperatures for the valves, Pressurizer Relief Tank Temperature Pressurizer Relief Tank Level OPERABLE.
SALEM - UNIT 2                                                                    3/4 3-51a                        Amendment No. 263

TABLE 3.3-11  (continued)
TABLE NOTATION ACTION 1    With the number of OPERABLE accident monitoring channels less than the Required Number of Channels shown in Table 3.3-11, restore the inoperable channel(s) to OPERABLE status within 7 days, or be in HOT SHUTDOWN within the next 12 hours.
ACTION 2    With the number of OPERABLE accident monitoring channels less than the Minimum Number of Channels shown in Table 3.3-11, restore the inoperable channel(s) to OPERABLE status within 48 hours or be in HOT SHUTDOWN within the next 12 hours.
ACTION 3    deleted ACTION 4    With the number of OPERABLE channels one-less than the Required Number of Channels shown in Table 3.3-11, operations may proceed provided that an OPERABLE Steam Generator Wide Range Level channel is available as an alternate means of indication for the Steam Generator with no OPERABLE Auxiliary Feedwater Flow Rate Channel.
ACTION 5    deleted SALEM - UNIT 2                        3/4 3-51b          Amendment No. 206

TABLE 3.3-11 (continued)
TABLE NOTATION ACTION 6     With the number of OPERABLE channels less than the Minimum Number of channels shown in Table 3.3-11, restore the inoperable channel(s) to OPERABLE status within 7 days, or be in HOT SHUTDOWN within the next 12 hours.
ACTION 7     With the number of OPERABLE channels one less than the Required Number of Channels shown in Table 3.3-11, operation may proceed until the next CHANNEL CALIBRATION (which shall be performed upon the next entry into MODE 5, COLD SHUTDOWN).
ACTION 8     With one RVLIS channel inoperable, restore the RVLIS channel to OPERABLE status within 30 days, or submit a special report in accordance with Specification 6.9.4.
ACTION 9     With both RVLIS channels inoperable, restore one channel to OPERABLE status within 7 days or submit a special report in accordance with Specification 6.9.4.
ACTION 10    With the number of OPERABLE Channels less than required by the minimum channels OPERABLE requirements,  initiate the preplanned alternate method of monitoring the appropriate parameter within 72 hours, and:
: 1) either restore the inoperable Channel(s) to OPERABLE status within 7 days of the event, or
: 2)  prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within 14 days following the event outlining the actions taken, the cause of the inoperability and the plans and schedule for restoring the system to OPERABLE status.
SALEM - UNIT 2                   3/4 3-51c                 Amendment No. 253

TABLE 4.3-11 SURVEILLANCE REQUIREMENTS FOR ACCIDENT MONITORING INSTRUMENTATION CHANNEL CHANNEL         CHANNEL          FUNCTIONAL INSTRUMENT                                       CHECKS"1 ) CALIBRATION(1 )          TESTV)
: 1. Reactor Coolant Outlet Temperature -                                                N.A.
THOT (Wide Range)
: 2. Reactor Coolant Inlet Temperature -                                                 N.A.
TcOLD  (Wide Range)
: 3. Reactor Coolant Pressure (Wide Range)                                               N.A.
: 4. Pressurizer Water Level                                                             N.A.
: 5. Steam Line Pressure                                                                 N.A.
: 6. Steam Generator Water Level                                                         N.A.
(Narrow Range)
: 7. Steam Generator Water Level                                                         N.A.
(Wide Range)
: 8. Refueling Water Storage Tank Water Level                                            N.A.
: 9. deleted
: 10. Auxiliary Feedwater Flow Rate                    S/U#                              N.A.
: 11. Reactor Coolant System Subcooling                                                  N.A.
Margin Monitor
#       Auxiliary Feedwater System is used on each startup and flow rate indication is verified at that time.
The instruments used to develop RCS subcooling margin are calibrated in accordance with the Surveillance Frequency Control Program; the monitor will be compared with calculated subcooling margin for known input values in accordance with the Surveillance Frequency Control Program.
SALEM - UNIT 2                              3/4 3-52                        Amendment No. 282

TABLE 4.3-11 (Continued)
SURVEILLANCE REQUIREMENTS FOR ACCIDENT MONITORING INSTRUMENTATION CHANNEL CHANNEL         CHANNEL        FUNCTIONAL INSTRUMENT                                         CHECKS"1'   CALIBRATION"1 )        TEST")
: 12. PORV Position Indicator                                          N.A.
: 13. PORV Block Valve Position Indicator                              N.A.
: 14. Pressurizer Safety Valve Position Indicator                      N.A.
: 15. Containment Pressure - Narrow Range                                                 N.A.
: 16. Containment Pressure - Wide Range                                                   N.A.
: 17. Containment Water Level - Wide Range                                                N.A.
: 18. Core Exit Thermocouples                                                             N.A.
: 19. Reactor Vessel Level Instrumentation                                                N.A.
System (RVLIS) 20, Containment High Range Accident Radiation monitor
: 21. Main Steamline Discharge (Safety Valves and Atmospheric Steam Dumps) Monitor Table Notation (1)    Frequencies are specified in the Surveillance Frequency Control Program unless otherwise noted in the table.
Unless the block valve is closed in order to meet the requirements of Action b, or c in specification 3.4.5.
SALEM - UNIT 2                              3/4 3-52a                      Amendment No. 282

INSTRUMENTATION RADIOACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.3.8 The radioactive liquid effluent monitoring instrumentation channels shown in Table 3.3-12 shall be OPERABLE to ensure that the limits of ODCM Control 3.11.1.1 are not exceeded.
APPLICABILITY: At all times.
ACTION:
: a. Not Used
: b. With less than the minimum number of radioactive liquid effluent monitoring instrumentation channels OPERABLE, take the ACTION shown in Table 3.3-12.
Exert best efforts to return the instrument to OPERABLE status within 30 days and, if unsuccessful, explain in the next annual radioactive effluent release report why the inoperability was not corrected in a timely manner.
: c. The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REQUIREMENTS 4.3.3.8 Each radioactive liquid effluent monitoring instrumentation channel shall be demonstrated OPERABLE by performance of the CHANNEL CHECK, CHANNEL CALIBRATION, and CHANNEL FUNCTIONAL TEST operations at the frequencies specified in the Surveillance Frequency Control Program unless otherwise noted in Table 4.3-12.
SALEM - UNIT 2                                3/4 3-53                        Amendment No. 282

TABLE 3.3-12 RADIOACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION MINIMUM CHANNELS INSTRUMENT                                                       OPERABLE               ACTION I. Not Used
: 2. Not Used
: 3. Not Used
: 4. TANK LEVEL INDICATING DEVICES
: a. Temporary Outside Storage Tanks as Required                 I                    30 TABLE NOTATION ACTION 26     Not Used ACTION 27     Not Used ACTION 28     Not Used ACTION 29     Not Used ACTION 30     With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, liquid additions to this tank may continue for up to 30 days provided the tank liquid level is estimated during all   liquid additions to the tank.
11 ACTION 31 -   Not Used SALEM - UNIT 2                                      3/4 3-54                         Amendment No. 215 a                                                     0

TABLE 4.3-12 RADIOACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQLIIREMENTS CHANNEL CHANNEL       SOURCE          CHANNEL          FUNCTIONAL INSTRUMENT                               CHECK(1 )     CHECK(1"     CALIBRATION(1 )        TEST(')
: 1. Not Used
: 2. Not Used
: 3. Not Used
: 4. TANK LEVEL INDICATING DEVICES**
: a. Temporary Outside Storage             D*            N.A.
Tanks as Required TABLE NOTATION During liquid additions to the tank.
If tank level indication is not provided, verification will be done by visual inspection.
(1)    Frequencies are specified in the Surveillance Frequency Control Program unless otherwise noted in the table.
SALEM - UNIT 2                                  3/4 3-55                         Amendment No. 282

Pages 3/4 3-57 through 3/4 3-64 Deleted SALEM - UNIT 2               3/4 3-56                  Amendment No. 265

INSTRUMENTATION POWER DISTRZBUTION-MONITORING SYSTEM LIMITING CONDITION FOR OPERATION 3.3.3.14 The Power Distribution Monitoring System tPDNS) shall be OPERABLE with:
a, A minimum of the following inputs from the plant available for use by the PDHS as defined in Table 3.3-14.
: 1. Control Bank Position
: 2. Tcold
: 3. Reactor Power Level
: 4. NIS Power Range Detector Section Signals
: b. Core Exit Thermocouples (T/C) meeting the criteria:
: 1. At least 25% operable T/C with at least 2 T/C per quadrant, and
: 2. The T/C pattern has coverage of all interior fuel assemblies (no face along the baffle), within a chose Xnight's move, radially, from a responding, calibrated T/C, or
: 3. At least 25%, operable T/C with at least 2 T/C per quadrant, and the einsalled PDMS calibration was determined within the last 31 Effective Full Power Days (EFPD).
: 4. The T/C temperatures used by the PDMS are calibrated via cross calibration with the loop temperature meesurement !tTba, and using the T/C flow mixing factor* determined during installed P=46 calibration.
: c. An installed PDMS calibration satisfying the criteria;
: 1. The initial calibration in each operating cycle is determined using measurements tzom at least 75% of the incore movable detector thimbles obtained at a THERMAL POWER greater then 25% of RATED THERMAL POWER.
: 2. The calibration in determined using measurements from at least 50% of the im&#xa2;ore movable detector thimbles at any time except as specified in 3.3.3.14.e.1, and
: 3. The calibration is determined using a minimum of 2 detector thimbles per core quadrant.
42AW   . y~?"y'"
              **   a.w                  'A J A '2 C                  inn AmSawncnZ 240. ~Zia

INSTRUMENTATION POWER DISTRIBUTION MONITORING SYSTEM LIMITING CONDITION FOR OPERATION (Continued)
APPLICABILTY:       MODE 1, above 25% RATED THERMAL POWER (RTP)
ACTION:
With any of the operability criteria listed in 3.3.3.14.a, 3.3.3.14.b, or 3.3.3.14.c not met, either correct the deficient operability condition, or declare the PDMS inoperable and use the incore movable detector system to obtain any required core power distribution measurements.
Increase the measured core peaking factors using the values listed in the COLR for the PDMS inoperable condition.
The provisions of Specification 3.0.3 are not applicable.
SURVEI LLANCE REQUIREMENTS 4.3.3.14.1 The operability criteria listed in 3.3.3.14.a, 3.3.3.14.b, and 3.3.3.14.c shall be verified to be satisfied prior to acceptance of the PDMS core power distribution measurement results.
4.3.3.14.2 Calibration of the PDMS is required:
: a.      In accordance with the Surveillance Frequency Control Program when the minimum number and core coverage criteria as defined in 3.3.3.14.b.1 and 3.3.3.14.b.2 are satisfied, or
: b.      In accordance with the Surveillance Frequency Control Program when only the minimum number criterion as defined in 3.3.3.14.b.3 is satisfied.
SALEM - UNIT 2                                   3/4 3-66                         Amendment No. 282

INSTRUMENTATION REQUTRED PDMS PLANT INPUT INFORMATION PLANT INPUT INFO RKATION        AVAILABLE      MINIMUM NO. or     APPICVABLE INUSVALID INPUTS               MODES Control Bank Position                  4                4a                ic Tcold                                  4                21 Reactor Power Level                     3 NIS Power Range Excoz'e Detector Section Signals TABLE NOTATIONS
: a.      Determined from either valid Demand Position or the average of =he valid individual RCCA position indications for all RCCAv in the Control Bank.
: b.      Determined from either the reactor 'TERKAL POWER derived using a valid to           secondary calorimetric measurement, the average NIS Poute Range Detector Power,  or the average RCS Loop AT.
C.      Greater than 25% RTP,
: d.      Comprised of an upper and lower detector section signal per Power Range Channel; a minimum of 3 OPERABLE channels required.
 *0 SALEM -    UNWZT 2                     3/4 3-67 Amendment No. 218

3/4.4 REACTOR COOLANT SYSTEM 3/4.4.1 REACTOR COOLANT LOOPS AND COOLANT CIRCULATION STARTUP AND POWER OPERATION LIMITING CONDITION FOR OPERATION 3.4.1.1 All reactor coolant loops shall be in operation.
APPLICABILITY: MODES 1 and 2.*
ACTION:
With less than the above required reactor coolant loops in operation, be in at least HOT STANDBY within 1 hour.
SURVEILLANCE REQUIREMENT 4.4.1.1 The above required reactor coolant loops shall be verified to be in operation and circulating reactor coolant in accordance with the Surveillance Frequency Control Program.
*See Special Test Exception 3.10.4.
SALEM - UNIT 2                                 3/4 4-1                       Amendment No. 282

REACTOR COOLANT SYSTEM HOT STANDBY.
LIMITING CONDITION FOR OPERATION 3.4.1.2    a. At least two of the reactor coolant loops listed below shall be OPERABLE:
: 1. Reactor Coolant Loop 21 and its associated steam generator and reactor coolant pump,
: 2. Reactor\Coolant Loop 22 and its associated steam generator and reactor coolant pump,
: 3. Reactor Coolant Loop 23 and its associated steam generator and reactor coolant pump,
: 4. Reactor Coolant Loop 24 and Its associated steam generator and reactor coolant pump.
: b. At least one of the above coolant loops shall be in operation* when the rod control system is deener gi zed**.
: c. All of the above coolant loops shall he in operation when the rod control system is energized**.
APPLICABILITY:      MODE 3 ACTION:
: a. With less than the above required reactor coolant loops OPERABLE, restore the required loops to OPERABLE status within 72 hours or be in HOT SHUTDOWN within the next 12 hours.
: b. With no reactor coolant loop in operation, suspend all operations involving a reduction in boron concentration of the Reactor Coolant System and immediately initiate corrective action to return the required coolant loop to operation.
SALEM - UNIT 2                  3/4 4-2                    Amendment No. 44

REACTOR COOLANT SYSTEM HOT STANDBY SURVEILLANCE REQUIREMENTS 4.4.1.2.1 At least the above required reactor coolant pumps, if not in operation, shall be determined to be OPERABLE in accordance with the Surveillance Frequency Control Program by verifying correct breaker alignments and indicated power availability.
4.4.1.2.2 At least one cooling loop shall be verified to be in operation and circulating reactor coolant in accordance with the Surveillance Frequency Control Program.
4.4.1.2.3 The required steam generator(s) shall be determined OPERABLE by verifying secondary side water level to be greater than or equal to 5% (narrow range) in accordance with the Surveillance Frequency Control Program.
All reactor coolant pumps may be de-energized for up to 1 hour provided: (1) no operations are permitted that would cause dilution of the reactor coolant system boron concentration (2) core outlet temperature is maintained at least 10&deg;F below saturation temperature, and (3) the rod control system is de-energized**
The rod control system shall be considered de-energized when one or more of the following conditions exist:
: 1)      Both Rod Drive MG set motor breakers are open.
: 2)      Both Rod Drive MG set generator breakers are open.
: 3)      A combination of at least three of the Reactor Trip and/or Reactor Trip Bypass Breakers are open.
If none of the above conditions for de-energizing the rod control system are met; the system shall be considered energized.
SALEM - UNIT 2                                3/4 4-2a                        Amendment No. 282

REACTOR COOLANT SYSTEM HOT SHUTDOWN LIMITING CONDITION FOR OPERATION 3.4.1.3        a. At least two of the coolant loops listed below shall be OPERABLE:
: 1. Reactor Coolant Loop 21 and its associated steam generator and reactor coolant pump,*
: 2. Reactor Coolant Loop 22 and its  associated steam generator and reactor coolant pump,*
: 3. Reactor Coolant Loop 23 and its associated steam generator and reactor coolant pump,*
: 4. Reactor Coolant Loop 24 and its associated steam generator and reactor coolant pump,*
S. Residual Heat Removal Loop 21,
: 6. Residual Heat Removal Loop 22.
: b. At least one of the above coolant loops shall be in operation.**
APPLICABILITY: MODE 4.
ACTION:
: a. With less than the above required loops OPERABLE, immediately initiate corrective action to return the required loops to OPERABLE status as soon as-possible; be in COLD SHUTDOWN within 20 hours.
: b. With no coolant loop in operation, suspend all operations involving a reduction in boron concentration of the Reactor Coolant System and ii-ediately initiate corrective action to return the required coolant loop to operation.
   *A reactor coolant pump shall not be started with one or more of the RCS cold leg temperatures less than or equal to 3120F unless 1) the pressurizer water volume is less than 1650 cubic feet (equivalent to approxLmately 92%
of level) or 2) the secondary water temperature of each steam generator is less than 500? above each of the RCS cold leg temperatures.
  **All reactor coolant pumps and residual heat removal pumps may be de-energized for up to 1 hour provided 1) no operations are permitted that would cause dilution of the reactor coolant system boron concentration, and 2) core outlet temperature is maintained at least 100F below saturation temperature.
SALEM - UNIT 2                         3/4 4-3                  Amendment No. 206

REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS 4.4.1.3.2 The required reactor coolant pump(s), if not in operation, shall be determined to be OPERABLE in accordance with the Surveillance Frequency Control Program by verifying correct breaker alignments and indicated power availability.
4.4.1.3.3 The required steam generator(s) shall be determined OPERABLE by verifying secondary side water level to be greater than or equal to 5% (narrow range) in accordance with the Surveillance Frequency Control Program.
4.4.1.3.4 At least one coolant loop shall be verified to be in operation and circulating reactor coolant in accordance with the Surveillance Frequency Control Program.
SALEM - UNIT 2                                3/4 4-4                         Amendment No. 282

REACTOR COOLANT SYSTEM COLD SHUTDOWN LIMITING CONDITION FOR OPERATION 3.4.1.4 Two# residual heat removal loops shall be OPERABLE* and at least one RHR loop shall be in operation.**
APPLICABILITY: MODE 5.##
ACTION:
: a.      With less than the above required loops operable, immediately initiate corrective action to return the required loops to OPERABLE status as soon as possible.
: b.      With no RHR loop in operation; suspend all operations involving a reduction in boron concentration of the Reactor Coolant System and immediately initiate corrective action to return the required RHR loop to operation.
SURVEILLANCE REQUIREMENTS 4.4.1.4 At least one residual heat removal loop shall be verified to be in operation and circulating reactor coolant in accordance with the Surveillance Frequency Control Program.
#        One RHR loop may be inoperable for up to two hours for surveillance testing, provided the other RHR loop is OPERABLE and in operation. Additionally, four filled reactor coolant loops, with at least two steam generators with their secondary side water levels greater than or equal to 5% (narrow range), may be substituted for one residual heat removal loop.
##       A reactor coolant pump shall not be started with one or more of the RCS cold leg temperatures less than or equal to 312"F unless 1) the pressurizer water volume is less than 1650 cubic feet (equivalent to approximately 92% of level), or 2) the secondary water temperature of each steam generator is less than 50'F above each of the RCS cold leg temperatures.
Systems supporting RHR loop operability may be excepted as follows:
: a.      The normal or emergency power source may be inoperable.
**       The residual heat removal pumps may be de-energized for up to 2 hours provided 1) no operations are permitted that would cause dilution of the reactor coolant system boron concentration, and 2) core outlet temperature is maintained at least 10'F below saturation temperature.
SALEM - UNIT 2                                  3/4 4-4a                       Amendment No. 282

6 THIS PAGE LEFT INTENTIONALLY BLANK 4
94 SALEM - UNIT 2               3/4 4-4b             Amendment No.1

REACTOR COOLANT SYSTEM 3/4.4.2 SAFETY VALVES SAFETY VALVES - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.4.2 A minimum of one pressurizer code safety valve shall be OPERABLE* with a lift setting of 2485 psig +/- 3%.**,***
APPLICABILITY: Mode 4 and 5 ACTION:
With no pressurizer code safety valve OPERABLE, immediately suspend all operations involving positive reactivity changes and place an OPERABLE RHR loop into operation in the shutdown cooling mode.
SURVEILLANCE REQUIREMENTS 4.4.2.1 No additional Surveillance Requirements other than those. required by the Inservice Testing Program.
While in Mode 5, an equivalent size vent pathway may be used provided that the vent pathway is not isolated or sealed.
**      The lift setting pressure shall correspond to ambient conditions of the valve at nominal operating temperature and pressure.
Following testing the lift setting shall be reset to within +/- 1%.
SALEM - UNIT 2                                   3/4 4-5                      Amendment No. 279

REACTOR COOLANT SYSTEM 3/4.4.3 SAFETY VALVES - OPERATING LIMITING CONDITION FOR OPERATION 3.4.3 All pressurizer code safety valves shall be OPERABLE with a lift setting of 2485 psig +/- 3%.*,**
APPLICABILITY: MODES 1, 2 and 3.
ACTION:
With one pressurizer code safety valve inoperable, either restore the inoperable valve to OPERABLE status within 15 minutes or be in HOT SHUTDOWN within 12 hours.
SURVEILLANCE REQUIREMENTS 4.4.3 No additional Surveillance Requirements other than those required by the Inservice Testing Program.
The lift setting pressure shall correspond to ambient conditions of the valve at nominal operating temperature and pressure.
Following testing the lift setting shall be reset to +/- 1%.
SALEM - UNIT 2                                   3/4 4-6                      Amendment No. 279

REACTOR COOLANT SYSTEM 3/4.4.4 PRESSURIZER LIMITING CONDITION FOR OPERATION 3.4.4 The pressurizer shall be OPERABLE with a water volume of less than or equal to 1650 cubic feet (92% indicated level), and at least two groups of pressurizer heaters each having a capacity of > 150 kw and capable of being powered from an emergency power supply.
APPLICABILITY: MODES 1, 2, and 3.
ACTION:
: a. With the pressurizer inoperable due to an inoperable emergency power supply to the pressurizer heaters either restore the inoperable emergency power supply within 72 hours or be in at least HOT STANDBY within the next 6 hours and in HOT SHUTDOWN within the following 6 hours.
: b. With the pressurizer otherwise inoperable, be in at least HOT. STANDBY with the reactor trip breakers open within 6 hours and in HOT SHUTDOWN within the following 6 hours.
SURVEILLANCE REQUIREMENTS 4.4.4.1 The pressurizer water volume shall be determined to be within its limit in accordance with the Surveillance Frequency Control Program.
4.4.4.2 The capacity of each of the above required groups of pressurizer heaters shall be verified by measuring circuit current in accordance with the Surveillance Frequency Control Program.
4.4.4.3 The emergency power supply for the pressurizer heaters shall be demonstrated OPERABLE in accordance with the Surveillance Frequency Control Program by manually transferring power from the normal to the emergency power supply and energizing the heaters.
SALEM - UNIT 2                                3/4 4-7                        Amendment No. 282

REACTOR COOLANT SYSTEM 3/4.4.5 RELIEF VALVES LIMITING CONDITION FOR OPERATION 3.4.5     Two power relief valves (PORVs)    and their associated block valves shall be OPERABLE.
APPLICABILITY:   MODES 1, 2,  and 3.
ACTION:
: a. With one or both PORVs inoperable because of excessive seat leakage, within 1 hour either restore the PORV(s) to OPERABLE status or close     I the associated block valve(s) with power maintained to the block valve(s); otherwise, be in at least HOT STANDBY within the next 6 hours and in HOT SHUTDOWN within the following 6 hours.
: b. With one PORV inoperable due to causes other than excessive seat leakage, within 1 hour either restore the PORV to OPERABLE status or    I close its associated block valve and remove power from the block valve; restore the PORV to OPERABLE status within the following 72 hours or be in HOT STANDBY within the next 6 hours and in HOT SHUTDOWN within the following 6 hours.
: c. With both PORVs inoperable due to causes other than excessive seat leakage, within 6 hours either restore at least one PORV to OPERABLE status or close the associated block valves and. remove power from the block valves and be in HOT STANDBY within the next 6 hours and in HOT SHUTDOWN within the following 6 hours. Restore the remaining PORV to OPERABLE status within 72 hours from failure of that valve to meet the Limiting Condition for Operation.
: d. With one block valve inoperable, within 1 hour restore the block valve to OPERABLE status or place the associated PORV in manual control;  restore the block valve to operable status within 72 hours or be in at least HOT STANDBY within the next 6 hours and in HOT SHUTDOWN within the following 6 hours.
: e. With both block valves inoperable, within 1 hour restore the block valves to OPERABLE status or place the associated PORVs in manual control; restore at least one block valve to OPERABLE status within the next 6 hours or be in at least HOT STANDBY within the next 6 hours and in HOT SHUTDOWN within the following 6 hours. Restore the remaining block valve to OPERABLE status within 72 hours from failure of that valve to meet the Limiting Condition for Operation.
SALEM - UNIT 2                       3/4 4-8              Amendment No. 177

REACTOR COOLANT SYSTEM 3/4.4.5 RELIEF VALVES SURVEILLANCE REQUIREMENTS 4.4.5.1 In addition to the requirements of the Inservice Testing Program, each PORV shall be demonstrated OPERABLE in accordance with the Surveillance Frequency Control Program by:
: a.      Operating the PORV through one complete cycle of full travel during MODES 3 or 4, and
: b.      Operating solenoid valves, air control valves, and check valves on associated air accumulators in PORV control systems through one complete cycle of full travel, and
: c.      Performing a CHANNEL CALIBRATION of the actuation instrumentation.
4.4.5.2 Each block valve shall be demonstrated OPERABLE in accordance with the Surveillance Frequency Control Program by operating the valve through one complete cycle of full travel unless the block valve is closed in order to meet the requirements of ACTION b, or c in Specification 3.4.5.
SALEM - UNIT 2                                 3/4 4-8a                       Amendment No. 282

REACTOR COOLANT SYSTEM 3/4.4.6   STEAM GENERATOR      (SG)  TUBE INTEGRITY LIMITING CONDITION FOR OPERATION 3.4.6 SG tube integrity        shall be maintained and all     SG tubes satisfying the tube repair criteria      shall be plugged in accordance with the Steam Generator Program.
APPLICABILITY:      MODES 1, 2,     3 and 4.
ACTION:
a.*    With one or more SG tubes satisfying the tube repair criteria          and not plugged in accordance with the Steam Generator Program:
: 1. Verify tube integrity       of the affected tube(s) is maintained until   the next refueling outage or SG tube inspection within 7 days; and
: 2. Plug the affected tube(s) in accordance with the Steam Generator Program prior to entering HOT SHUTDOWN following         the next refueling outage or SG tube inspection.
: b.      With SG tube integrity      not maintained or the required Action of a.
above not met, be in at least HOT STANDBY within 6 hours and in at least COLD SHUTDOWN within the following 30 hours.
SURVEILLANCE REQUIREMENTS 4.4.6.1    Verify SG tube integrity        in  accordance with the Steam Generator Program.
4.4.6.2    Verify that each inspected SG tube that satisfies          the tube repair criteria    is plugged in accordance with the Steam Generator Program prior to entering HOT SHUTDOWN following a SG tube inspection
* Separate Action is       allowed for each SG tube.
SALEM - UNIT 2                                3/4 4-9                  Amendment No. 262

Pages 3/4 4-10 through 3/4   4-15a Deleted I
SALEM - UNIT 2
3/4 4-10 through 3/4 4-15a Amendment No. 262

REACTOR COOLANT SYSTEM 3/4.4.7 REACTOR COOLANT SYSTEM LEAKAGE LEAKAGE DETECTION SYSTEMS LIMITING CONDITION FOR OPERATION 3.4.7.1 The following Reactor Coolant System leakage detection systems shall be OPERABLE:
: a. The containment atmosphere particulate radioactivity monitoring system,
: b. The containment pocket sump level monitoring system, and
: c. Either the containment fan cooler condensate flow rate or the containment atmosphere gaseous radioactivity monitoring system.
APPLICABILITY: MODES 1, 2, 3 and 4.
ACTION:
With only two of the above required leakage detection systems OPERABLE, operation may continue for up to 30 days provided grab samples of the containment atmosphere are obtained and analyzed at least once per 24 hours when the required gaseous and/or particulate radioactivity monitoring system is inoperable; otherwise, be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
SURVEILLANCE REQUIREMENTS 4.4.7.1 The leakage detection systems shall be demonstrated OPERABLE by:
: a. Containment atmosphere particulate and gaseous (if being used) monitoring systems-performance of CHANNEL CHECK, SOURCE CHECK, CHANNEL CALIBRATION and CHANNEL FUNCTIONAL TEST in accordance with the Surveillance Frequency Control Program.
: b. Containment pocket sump level and containment fan cooler condensate flow rate (if being used) monitoring systems-performance of CHANNEL CALIBRATION in accordance with the Surveillance Frequency Control Program.
SALEM - UNIT 2                               3/4 4-16                        Amendment No. 282

OPERATIONAL LEAKAGE LIMITING CONDITION FOR OPERATION 3.4.7.2 Reactor Coolant System leakage shall be limited to:
: a. No PRESSURE BOUNDARY LEAKAGE,
: b.      1 GPM UNIDENTIFIED LEAKAGE,
: c.      150 gallons per day primary-to-secondary leakage through any one steam generator, and
: d.      10 GPM IDENTIFIED LEAKAGE from the Reactor Coolant System, and
: e.      NOT USED
: f.      1 GPM leakage at a Reactor Coolant System pressure of 2230 +/- 20 psig from any Reactor Coolant System Pressure Isolation Valve specified in Table 3.4-1.
APPLICABILITY: MODES 1, 2, 3 and 4 ACTION:
: a. With any PRESSURE BOUNDARY LEAKAGE, or primary-to-secondary leakage not within limit, be in at least HOT STANDBY within 6 hours and in COLD SHUTDOWN within the following 30 hours.
: b. With any Reactor Coolant System leakage greater than any one of the above limits, excluding PRESSURE BOUNDARY LEAKAGE and leakage from Reactor Coolant System Pressure Isolation Valves, and primary-to-secondary leakage, reduce the leakage rate to within limits within 4 hours or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
: c. With any Reactor Coolant System Pressure Isolation Valve leakage greater than the above limit, isolate the high pressure portion of the affected system from the low pressure portion within 4 hours by use of at least two closed manual or deactivated automatic valves, or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
SURVEILLANCE REQUIREMENTS 4.4.7.2.1 Reactor Coolant System leakages shall be demonstrated to be within each of the above limits by:
: a.      Monitoring the containment atmosphere particulate radioactivity monitor in accordance with the Surveillance Frequency Control Program.
: b.      Monitoring the containment sump inventory in accordance with the Surveillance Frequency Control Program.
SALEM - UNIT 2                                  3/4 4-17                       Amendment No. 282

SURVEILLANCE REQUIREMENTS (Continued) c*. Verifying primary-to-secondary leakage is : 150 gallons per day through any one steam generator in accordance with the Surveillance Frequency Control Program during steady state operation, d*. Performance of a Reactor Coolant System water inventory balance** in accordance with the Surveillance Frequency Control Program. The water inventory balance shall be performed with the plant at steady state conditions.
The provisions of specification 4.0.4 are not applicable for entry into Mode 4, and
: e.      Monitoring the reactor head flange leakoff system in accordance with the Surveillance Frequency Control Program.
4.4.7.2.2 Each Reactor Coolant System Pressure Isolation Valve specified in Table 3.4-1 shall be demonstrated OPERABLE pursuant to the Inservice Testing Program, except that in lieu of any leakage testing required by the Inservice Testing Program, each valve shall be demonstrated OPERABLE by verifying leakage to be within its limit:
: a.      In accordance with the Surveillance Frequency Control Program.
: b.      Prior to entering MODE 2 whenever the plant has been in COLD SHUTDOWN for 72 hours or more and if leakage testing has not been performed in the previous 9 months.
: c.      Prior to returning the valve to service following maintenance repair or replacement work on the valve.
: d.      For the Residual Heat Removal and Safety Injection Systems hot and cold leg injection valves and accumulator valves listed in Table 3.4-1 the testing will be done within 24 hours following valve actuation due to automatic or manual action or flow through the valve. For all other systems testing will be done once per refueling.
The provisions of specification 4.0.4 are not applicable for entry into MODE 3 or 4.
Not required to be completed until 12 hours after establishment of steady state operation.
Not applicable to primary-to-secondary leakage.
SALEM - UNIT 2                                 3/4 4-18                         Amendment No. 282

REACTOR COOLANT SYSTU TABLE 3.4-1 REACTOR COOLANT SYSTEK PRESS9J1  ISOLATION VKLVES VALVE NO 21SJ43             Safety Injection (L.P. from RHR Pumps to Cold Legs) 223SJ43            Safety Injection (L.P. from         Pumps to Cold Legs) 23SJ43             Safety Injection (L.P. from RNA Pumps to Cold Legs) 24SJ43             Safety Injection (L.P. from         Pumps to Cold Legs) 21SJ55             Safety Injection (Accumulator Discharge to Col .d Legs) 22SJ55             Safety Injection (Accumulator Discharge to Col ,dLegs I 23SJ55             Safety Injection (Accumulator Discharge to Col .dLegs I 24SJ55             Safety Injection (Accumulator Discharge to Col d Legs) 21SJ56             Safety Injection (Accumulator Discharge to Col .d Legs) 22SJ56             Safety Injection (Accumulator Discharge to Col .d Legs) 23SJ56             Safety Injection (Accumulator Discharge to Col .d Legs I 24SJ56             Safety Injection (Accumulator Discharge to Col .d Legs) 21SJ17             Safety Injection (Boron Injeci ti .on to Cold Legs) 22SJ17             Safety Injection (Boron Injeciti aon to Cold Legs) 23SJ17             Safety Injection (Boron Injeciti on to Cold Legs) 24SJ17             Safety Injection (Boron Injeciti on to Cold Legs) 2SJ150             Safety Injection (Boron Injeciti .on to Cold Legs) 21SJ139            Safety Injection (H.P. from S Pumps to lot Legal 22SJ139            Safety Injection (H.P. from S:I Pumps to Eot Legs) 23SJ139            Safety Injection (H.P. from s:I Pumps to got Legs) 24SJ139            Safety Injection (H.P. from 3: I Pumps to Not Legs) 21SJ156            Safety Injection (H.P. from S3 I Pumps to Not Legal 22SJ156            Safety Injection (H.P. from S:K Pumps to Eot Legs) 23SJ156            Safety Injection (H.P. from S:I Pumps to Hot Legs) 243J156            Safety Injection (H.P. from S:C Pumps to Eot Legs) 21SJ144            Safety Injection (H.P. from S:C Pumps to Cold Legs) 22SJ144            Safety Injection (H.P. from S:C Pumps to Cold Legs) 23SJ144            Safety Injection (H.P. from 5: Pumps to Cold Legs) 24SJ144            Safety Injection (H.P. from S:I Pumps to Cold Legs) 2RE1               RE1 Suction from Hot Leg No. 2321 2R12               REN Suction from Hot Leg No. 23 23RH27             RNA Discharge to Hot Leg No. i 24R127             REN Discharge to Hot Leg No. 24 SALE9 - UNIT 2                 3/4 4-19               2Amendment No. 106

PAGES 3/4 4-20 THROUGH 3/4 4-22 DELETED SALEM - UNIT 2        3/4 4-20 through 3/4 4-22        Amendment No.161

REACTOR COOLANT SYSTEM 3/4,4,9 SPECIFIC ACTIVITY LIMITING CONDITION FOR OPERATION 3.4.9       The specific activity of the primary coolant shall be limited to:
: a. s 1,0 pCi/gram DOSE EQUIVALENT 1-131, -and
: b. i 1O0/fpCi/gram.
APPLICABILITY-    MODES 1, 2,  31 4 and 5.
ACTION:
MODES 1, 2 and 3*
a,  With the specific activity of the primary coolant > 1.0 pCi/gram DOSE EQUIVALENT 1-131 for more than 48 hours during one continuous time interval or exceeding the limit line shown on Figure 3.4-1, be in at least HOT STANDBY with Tv, < 500'F within 6 hours.
: b. With the specific activity of the primary coolant > 100/EpCi/gram, be in at least HOT STANDBY with Tvg < 500 0 F within 6 hours.
: c. LCO 3,0.4,c is applicable.
MODES 1, 2, 3, 4 and 5
: a. With the specific activity of the primary coolant > 1.0 pCi/gram DOSE EQUIVALENT 1-131 or > 100/EpCi/gram, perform the sampling and analysis requirements of item 4a of Table 4.4-4 until the specific activity of the primary coolant is restored to within its limits.
SURVEILLANCE REQUIREMENTS 4.4.9      The specific activity of the primary coolant shall be determined to be within the limits by performance of the sampling and analysis program of Table 4.4-4.
*With Tvg > 500&deg;F.
SALEM - UNIT 2                         3/4 4-23                Amendment No.258

ThLs page intentionally left blank.
0 SALEM - UNIT 2         3/4 4-24                 Amendment No. 112

TABLE 4.4-4 PRIMARY COOLANT SPECIFIC ACTIVITY SAMPLE AND ANALYSIS PROGRAM MODES IN WHICH SAMPLE AND TYPE OF MEASUREMENT                             SAMPLE AND ANALYSIS                 ANALYSIS AND ANALYS IS                                          FREQUENCY                    REQUIRED
: 1. Gross Activity Determination               In accordance with the          1,2,3,4 Surveillance Frequency Control Program
: 2. Isotopic Analysis for DOSE                 In accordance with the          1 EQUIVALENT 1-131 Concentration             Surveillance Frequency Control Program
: 3. Radiochemical for E Determination          In accordance with the          1 Surveillance Frequency Control Program*
: 4. Isotopic Analysis for Iodine               a) Once per 4 hours,            1#, 2#, 3#, 4#, 5#
Including 1-131, 1-133, and 1-135              whenever the specific activity exceeds 1.0 piCi/gram DOSE EQUIVALENT 1-131 or 100/P- pCi/gram, and b) One sample between 2         1,2,3 and 6 hours following a THERMAL POWER change exceeding 15 percent of the RATED THERMAL POWER within a one hour period.
#      Until the specific activity of the primary coolant system is restored within its limits.
* Sample to be taken after a minimum of 2 EFPD and 20 days of POWER OPERATION have elapsed since reactor was last subcritical for 48 hours or longer.
SALEM - UNIT 2                                  3/4 4-25                       Amendment No. 282

IPI-L                                         FT.      ,-T I-                                   jdVii+/-"-41 250              9 -
I I I lAI
                                                                    -1  . I I      . b.          1 E
200 I-                                                           UNACCEPTABLE
                                                                   "--7' OPERATION III07          l=
U-I C_
LU W_=                       1001 ACCEPTABLE-OPERATION l
                                     ~1~I 0
                     ! I I I I j I I I I I I VI f [&#xfd; J.-LIJ."       U I
20          30            40         50     60       70       80            90   100 PERCENT OF RATED THERMAL POWER FIGURE 3.4-1 DOSE EQUIVALENT 1-131 Primary Coolant Specific Activity Limit Versus Percent of RATED THERMAL POWER with the Primary Coolant Specific Activity > 1.0*Ci/gram Dose Equivalent 1-131 SALEM - UNIT 2                                       3/4 4-26

REACTOR COOLANT SYSTEM 3/4.4.10 PRESSURE/TEMPERATURE LIMITS REACTOR COOLANT SYSTEM LIMITING CONDITION FOR OPERATION 3.4.10.1 The Reactor Coolant System (except the pressurizer) temperature and pressure shall be limited in accordance with the limit lines shown on Figures 3.4-2 and 3.4-3 during heatup, cooldown, criticality, and inservice leak and hydrostatic testing with:
: a.      A maximum heatup of 100&deg;F in any one hour period,
: b.      A maximum cooldown of 100'F in any one hour period, and
: c. A maximum temperature change of less than or equal to 5&deg;F in any one hour period, during hydrostatic testing operations above system design pressure.
APPLICABILITY: At all times.
ACTION:
With any of the above limits exceeded, restore the temperature and/or pressure to within the limit within 30 minutes; perform an engineering evaluation to determine the effects of the out-of-limit condition on the structural integrity of the Reactor Coolant System; determine that the Reactor Coolant System remains acceptable for continued operation or be in at least HOT STANDBY within the next 6 hours and reduce the RCS Ta,, and pressure to less than 200'F and 500 psig, respectively, within the following 30 hours.
SURVEILLANCE REQUIREMENTS 4.4.10.1.1 The Reactor Coolant System temperature and pressure shall be determined to be within the limits in accordance with the Surveillance Frequency Control Program during system heatup, cooldown, and inservice leak and hydrostatic testing operations.
4.4.10.1.2 The reactor vessel material irradiation surveillance specimens shall be removed and examined, to determine changes in material properties, at the intervals required by 10 CFR 50, Appendix H. The results of these examinations shall be used to update Figures 3.4-2 and 3.4-3.
SALEM - UNIT 2                                   314 4-27                      Amendment No. 282

Limiting Material Property Weld 3-442 A&C Initial RTNDT -56"C RTNOT     after 32 EFPY:               1/4T  199&deg;F 3/4T  140 0 F 2500-2250      -                 -  Tilt -
2000              -
15oo  -                                                         -        -              -O....
1250 1000                                            --           CtULgMW i 250         '.'         '      '      'ep                    v@Speld  ....... ~i   2EF' 750 100        5eu      10       150     20    2..0..300    '350l&deg;   400l      45     50         55 250             q6..c     8Baltup T&#xfd;                                   &#xfd;N* p to Eo. Ipeldwc           lq i    Pl-,- 2 Pea. o "w~jin 0     50       100      150     200   250     300   350     400       480    800        550 Moderator Temperature (Dog. F)
Figure 3.4-2 SALEM UNIT 2 REACTOR COOLANT SYSTEM HEATUP LIMITATIONS APPLICABLE FOR THE FIRST 32 EPPY WITH MAXIMUM HEATUP RATE OF 100 F/HR.                           CURVE CONTAINS MARGIN FOR INSTRUMENT ERRORS SALEM  -  UNIT 2                                       3/4 4-28                     Amendment No.      224 0

Limiting Material Property Weld 3-442 A&C Initial RTNOT         -56*C RTNoT after 32 EFPY:          1/4T     199oF 3/4T     140&deg;F 2500-----
2250        -.-.-.
2000        -         -         -      --                           -      -     -
1750                        '                          "--
Jioo-1500 1250    -..
pao 1000               0      1                2EM 750     -4                                             _                 _
00'
                         -1000 2500                               F                    --
4----       For lnoI 0          50      t00      150     200    2W0      3W0 350    400    450   500 WO0 Moderator Temperature (Dog, F)
Figure 3.4-3 SALEM UNIT 2 REACTOR COOLANT SYSTEM COOLDOWN LIMITATIONS APPLICABLE FOR THE FIRST 32 EFPY WITH MAXIMUM COOLDOWN RATE OF 100 F/HR. CURVE CONTAINS MARGIN FOR INSTRUMENT ERRORS.
SALEM - UNIT 2                                      3/4 ,,,-29.                      Amendment No. 224

REACTOR COOLANT SYSTEM PRESSURIZER LIMITING CONDITION FOR OPERATION 3.4.10.2 The pressurizer temperature shall be limited to:
: a.      A maximum heatup of 100OF in any one hour period,
: b.      A maximum cooldown of 2000F in any one hour period, and
: c.      A maximum spray water temperature differential of 320&deg;F.
APPLICABILITY: At all times.
ACTION:
With the pressurizer temperature limits in excess of any of the above limits, restore the temperature to within the limits within 30 minutes; perform an engineering evaluation to determine the effects of the out-of-limit condition on the structural integrity of the pressurizer; determine that the pressurizer remains acceptable for continued operation or be in at least HOT STANDBY within the next 6 hours and reduce the pressurizer pressure to less than 500 psig within the following 30 hours.
SURVEILLANCE REQUIREMENTS 4.4.10.2 The pressurizer temperatures shall be determined to be within the limits in accordance with the Surveillance Frequency Control Program during system heatup or cooldown. The spray water temperature differential shall be determined to be within the limit in accordance with the Surveillance Frequency Control Program during auxiliary spray operation.
SALEM - UNIT 2                                3/4 4-30                           Amendment No. 282

REACTOR COOLANT SYSTEM OVERPRESSURE PROTECTION SYSTEMS LIMITING CONDITION FOR OPERATION 3.4.10.3    At least one of the following overpressure protection systems shall be OPERABLE:
: a. Two Pressurizer Overpressure Protection System relief valves     (POPS)   with a lift  setting of less than or equal to 375 psig, or
: b. The Reactor Coolant System (RCS) depressurized with an RCS vent of greater than or equal to 3.14 square inches.
APPLICABILITY:      When the temperature of one or more of the RCS cold legs is      less than or equal to 312'F, except when the reactor vessel head is removed.
ACTION:
: a. With one POPS inoperable in MODE 4 and the temperature of one or more of the RCS cold legs is less than or equal to 312 0 F, restore the inoperable POPS to OPERABLE status within 7 days or depressurize and vent the RCS through a 3.14 square inch vent(s) within the next 8 hours; maintain the RCS in a vented condition until both POPSs have been restored to OPERABLE status.
: b. With one POPS inoperable in MODES 5 or 6 with the Reactor Vessel Head installed, restore the inoperable POPS to OPERABLE status within 24 hours, or complete depressurization and venting of the RCS through at least a 3.14 square inch vent(s) within the next 8 hours; maintain the RCS in a vented condition until both POPSs have been restored to OPERABLE status.
: c. With both POPSs inoperable, depressurize and vent the RCS through a 3.14 square inch vent(s) within 8 hours; maintain the RCS in a vented condition until both POPSs have been restored to OPERABLE status.
: d. In the event either the POPS or the RCS vent(s) are used to mitigate a RCS pressure transient, a Special Report shall be prepared and submitted to:the Commission pursuant to Specification 6.9.2 within 30 days.        The report shall describe the circumstances initiating the transient, the effect of the POPS or vent(s) on the transient and any corrective action necessary to prevent recurrence.
: e. LCO 3.0.4.b is   not applicable when entering MODE 4.
SURVEILLANCE REQUIREMENTS 4.4.10.3.1     Each POPS shall be demonstrated OPERABLE by:
SALEM - UNIT 2                         3/4 4-31                  Amendment No. 258

REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS (Continued)
: a.      Performance of a CHANNEL FUNCTIONAL TEST on the POPS actuation channel, but excluding valve operation, within 31 days prior to entering a condition in which the POPS is required OPERABLE and in accordance with the Surveillance Frequency Control Program thereafter when the POPS is required OPERABLE.
: b.      Performance of a CHANNEL CALIBRATION on the POPS actuation channel in accordance with the Surveillance Frequency Control Program.
: c. Verifying the POPS isolation valve is open in accordance with the Surveillance Frequency Control Program when the POPS is being used for overpressure protection.
: d. Testing pursuant to the Inservice Testing Program.
4.4.10.3.2 The RCS vent(s) shall be verified to be open in accordance with the Surveillance Frequency Control Program* when the vent(s) is being used for overpressure protection.
Except when the vent pathway is provided with a valve which is locked, sealed, or otherwise secured in the open position, then verify these valves open in accordance with the Surveillance Frequency Control Program.
SALEM - UNIT 2                              3/4 4-32                         Amendment No. 282

REACTOR COOLANT SYSTEM 3.4.11 DELETED SALEM - UNIT 2        3/4 4-33 Amendment No. 281

REACTOR COOLANT SYSTEM 3/4.4.12 HEAD VENTS LIMITING CONDITION FOR OPERATION 3.4.12 Four reactor vessel head vent paths shall be operable with the vent paths closed. A vent path consists of at least two head vent valves in series, powered from vital sources, and associated flowpath.
APPLICABILITY: MODES 1, 2, 3 AND 4.
ACTION:
: a. With one, two or three reactor vessel head vent path(s) inoperable, STARTUP and/or POWER OPERATION may continue provided the inoperable vent path(s) is maintained closed with the valve actuators key locked in the closed position; restore the inoperable vent path(s) to OPERABLE status within 30 days, or, be in HOT STANDBY within 6 hours and in COLD SHUTDOWN within the following 30 hours.
: b. With four reactor vessel head vent paths inoperable; maintain the inoperable vent paths closed with power removed from the valve actuators of all the vent valves in the inoperable vent paths, and restore at least one of the vent paths to OPERABLE status within 72 hours or be in HOT STANDBY within 6 hours and in COLD SHUTDOWN within the following 30 hours.
SURVEILLANCE REQUIREMENTS 4.4.12 Reactor vessel head vent system vent paths shall be demonstrated OPERABLE in accordance with the Surveillance Frequency Control Program by:
: 1. Verifying all manual isolation valves in each vent path are locked in the open position.
: 2. Cycling each valve in the vent paths through at least one complete cycle of full travel from the control room during COLD SHUTDOWN or REFUELING.
: 3. Verifying flow through the reactor vessel head vent system vent path during venting.
SALEM - UNIT 2                               3/4 4-34                         Amendment No. 282

3/4.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)
ACCUMULATORS LIMITING CONDITION FOR OPERATION 3.5.1 Each reactor coolant system accumulator shall be OPERABLE with:
: a. The isolation valve open,
: b. A contained volume of between 6223 and 6500 gallons of borated water,
: c. A boron concentration of between 2200 and 2500 ppm, and
: d. A nitrogen cover-pressure of between 595.5 and 647.5 psig.
APPLICABILITY: MODES 1,2 and 3*.
ACTION:
: a. With one accumulator inoperable, except as a result of a closed isolation valve or boron concentration outside the required limits, restore the inoperable accumulator to OPERABLE status within 24 hours or be in HOT SHUTDOWN within the next 12 hours.
: b. With one accumulator inoperable due to the isolation valve being closed, either immediately open the isolation valve or be in HOT STANDBY within 24 hours and be in HOT SHUTDOWN within the next 12 hours.
: c. With the boron concentration of one accumulator outside the required limits, restore the boron concentration to within the required limits within 72 hours or be in at least HOT STANDBY within the next 6 hours and reduce pressurizer pressure to less than or equal to 1000 psig within the next 6 hours.
SURVEILLANCE REQUIREMENTS 4.5.1 Each accumulator shall be demonstrated OPERABLE:
: a. In accordance with the Surveillance Frequency Control Program by:
: 1.      Verifying the water level and nitrogen cover-pressure in the tanks, and
: 2.      Verifying that each accumulator isolation valve is open.
Pressurizer Pressure above 1000 psig.
SALEM - UNIT 2                               3/4 5-1                         Amendment No. 282

EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)
: b. In accordance with the Surveillance Frequency Control Program and within 6 hours after each solution volume increase of greater than or equal to 1% of tank volume by verifying the boron concentration of the accumulator solution.
C. In accordance with the Surveillance Frequency Control Program when the RCS pressure is greater than 1000 psig by verifying that the power lockout switch is in lockout.
: d. In accordance with the Surveillance Frequency Control Program by verifying that each accumulator isolation valve opens automatically upon receipt of a safety injection test signal.
SALEM - UNIT 2                            314 5-2                        Amendment No. 282

_-_-.r-?SENCY CORE COOLING SYSTEMS ECCS SU2BSYSTEMS -      T%9 _  350F LIM:TING C3NDITION FOR OPERATION 3.5.2 Two independent ECCS subsystems shall be OPERABLE with each subsystem comprised of the following injection syste s:
: a. One OPERABUL centrifugal charging pump and associated flow path capable of taking suction from the refueling water storage tank and transferring suction to the residual heat removal pump discharge piping and;
: 1. Discharging into each Reactor Coolant System (RCS)   cold leg.
: b. One OPERA.BLE safety injection pump and associated flow path capable of taking suction from the refueling water storage tank and transferring suction to the residual heat removal pump discharge piping and;
: 1. Discharging into each RCS cold leg,  and; upon manual initiation,
: 2. Discharging into its   two associated RCS hot legs.
: c. One OPERABLE residual heat removal pump and associated residual heat removal heat exchanger and flow path capable of taking suction from the refueling water storage tank on a safety injection signal and transferring suction to the containment sump during the recirculation phase of operation and;
: 1. Discharging into each RCS cold leg.
APPLICABILITY:      MODES 1, 2 and 3.
ACTION:
: a. With one ECCS subsystem inoperable, restore the inoperable subsystem to OPERABLE status within 72 hours or be in HOT SHUTDOWN within the next 12 hours.
: b. In the event the ECCS is actuated and injects water into the Reactor Coolant System, a Special Report shall be prepared and submitted to the Conmission pursuant to Specification 6.9.2 within 90 days describing the circumstances of the actuation and the total accumulated actuation cycles to date. The current value of the usage factor for each affected safety injection nozzle shall be provided in this Special Report whenever its value exceeds 0.70.
SALEM - UNIT 2                           3/4 5-3              Amendment No. 184   l

EMERGENCY CORE COOLING SYSTEMS ECCS SUBSYSTEMS - T-,. > 350&deg;F ACTION (Continued):
: c. With both ECCS subsystems inoperable for surveillance testing, restore at least one subsystem to OPERABLE status within 1 hour or be in at least HOT STANDBY within the next 6 hours and in at least HOT SHUTDOWN within the following 6 hours and at least COLD SHUTDOWN within the subsequent 24 hours.
SALEM - UNIT 2                            3/4 5-3a                      Amendment No. 70

EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS 4.5.2 Each ECCS subsystem shall be demonstrated OPERABLE:
: a.      In accordance with the Surveillance Frequency Control Program by:
: 1.      Verifying that the following valves are in the indicated positions with power to the valve operators removed:
Valve Number       Valve Function                              Valve Position
: a. 2 SJ 69       a. RHR pump suction                        a. open
: b. 2 SJ 30       b. SI pump suction                         b. open C. 21 SJ 40      C. SI discharge to hot legs                C. closed
: d. 22 SJ 40      d. SI discharge to hot legs                d. closed
: e. 2 RH 26       e. RHR discharge to hot legs               e. closed
: f. 21 SJ 49      f. RHR discharge to cold legs              f. open
: g. 22 SJ 49      g. RHR discharge to cold legs              g. open
: h. 2 CS 14#      h. Spray additive tank discharge           h. open
: i. 2 SJ 135        i. SI discharge to cold legs                i. open
: j. 2 SJ 67         j. SI recirc. line isolation                j.k. open
: k. 2 SJ 68         k. SI recirc. line isolation                     open
: 2.      Verifying that the following valves are in the indicated positions:
Valve Number       Valve Function                        Valve Position
: a. 21 RH 19        a. RHR crosstie valve                a. Open
: b. 22 RH 19        b. RHR crosstie valve                b. Open
: b.      In accordance with the Surveillance Frequency Control Program by:
: 1.      Verifying that each valve (manual, power operated or automatic) in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position.
: 2.      Verifying that the ECCS piping is full of water by venting the ECCS pump casings and accessible discharge piping high points.
#      If inoperable, the applicable Technical Specification is 3.6.2.2.
SALEM - UNIT 2                                  3/4 5-4                          Amendment No. 282 Corrected by letter dated April 17, 2012

EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)
: c. By a visual inspection which verifies that no loose debris (rags, trash, clothing, etc.) is present in the containment which could be transported to the containment sump and cause restriction of the pump suctions during LOCA conditions. This visual inspection shall be performed:
: 1.       For all accessible areas of the containment prior to establishing CONTAINMENT INTEGRITY, and
: 2.       In accordance with the Surveillance Frequency Control Program the areas affected within containment by containment entry and during the final entry when CONTAINMENT INTEGRITY is established.
: d. In accordance with the Surveillance Frequency Control Program by:
: 1.       A visual inspection of the containment sump and verifying that the subsystem suction inlets are not restricted by debris and that the sump components (trash racks, screens, etc.) show no evidence of structural distress or corrosion.
: e. In accordance with the Surveillance Frequency Control Program, during shutdown, by:
: 1.       Verifying that each automatic valve in the flow path actuates to its correct position on a safety injection test signal.
: 2.       Verifying that each of the following pumps start automatically upon receipt of a safety injection test signal:
a)       Centrifugal charging pump b)       Safety injection pump c)       Residual heat removal pump SALEM - UNIT 2                                3/4 5-5                       Amendment No. 282

EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)
: f. By verifying that each of the following pumps develops the indicated Total Dynamic Head (TDH) when tested at the test flow point pursuant to the Inservice Testing Program:
: 1.      Centrifugal Charging pump          - 2338 psi TDH
: 2.      Safety Injection pump              - 1369 psi TDH
: 3.      Residual Heat Removal pump         > 165 psi TDH
: g. By verifying the correct position of each of the following ECCS throttle valves:
: 1.      Within 4 hours following completion of each valve stroking operation or maintenance on the valve when the ECCS subsystems are required to be OPERABLE.
: 2.      In accordance with the Surveillance Frequency Control Program.
HPSI System                             LPSI System Valve Number                            Valve Number 21 SJ 16                                21 SJ 138 22SJ16                                  22SJ138 23SJ 16                                 23SJ 138 24SJ 16                                 24SJ138 21 SJ 143 22 SJ 143 23 SJ 143 24 SJ 143
: h. By performing a flow balance test, during shutdown, following completion of modifications to the ECCS subsystems that alter the subsystem flow characteristics and verifying that:
: 1. For Safety Injection pumps, with a single pump running:
a)      The sum of the injection line flow rates, excluding the highest flow rate, is ->453 gpm, and b)      The total flow rate through all four injection lines is 5 647 gpm, and c)      The difference between any pair of injection line flow rates is
                             -<12.0 gpm, and d)      The total pump flow rate is < 664 gpm in the cold leg alignment, and e)      The total pump flow rate is <- 654 gpm in the hot leg alignment.
SALEM - UNIT 2                              3/4 5-6                           Amendment No. 282

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EMERGENCY CORE COOLING SYSTEMS ECCS SUBSYSTEMS -   Tavg <350'F LIMITING CONDITION FOR OPERATION 3.5;3   As a minimum,   one ECCS subsystem comprised of the following shall be OPERABLE:
: a. One OPERABLE centrifugal charging pump and associated flow path capable of taking suction from the refueling water storage tank and transferring suction to the residual heat removal pump discharge piping and;
: 1. Discharging into each Reactor Coolant System (RCS)   cold leg.
: b. One OPERABLE residual heat removal pump and associated residual heat removal heat exchanger and flow path capable of taking suction from the refueling water storage tank on a safety injection signal and transferring suction to the containment sump during the recirculation phase of operation and;
: 1. Discharging into each RCS cold leg,  and; upon manual initiation,
: 2. Discharging into two RCS hot legs.
APPLICABILITY:  MODE 4.
ACTION:
: a. With no ECCS subsystem OPERABLE because of the inoperability of either the centrifugal charging pump or the flow path from the refueling water storage tank, restore at least one ECCS subsystem to OPERABLE status within 1 hour or be in COLD SHUTDOWN within the next 20 hours.
: b. With no ECCS subsystem OPERABLE because of the inoperability of either the residual heat removal heat exchanger or residual heat removal pump, restore at least one ECCS subsystem to OPERABLE status or maintain the Reactor Coolant System Tvg lessthan 350'F by use of alternate heat removal methods.
: c. In the event the ECCS is actuated and injects water into the Reactor Coolant System, a Special Report shall be prepared and submitted to the Commission pursuant to Specification 6.9.2 within 90 days describing the circumstances of the actuation and the total accumulated actuation cycles to date. The current value of the usage factor for each affected safety injection nozzle shall be provided in this Special Report whenever its value exceeds 0.70.
: d. LCO 3.0.4.b is   not applicable to ECCS high head subsystem
# A maximum of one safety injection pump or one centrifugal charging pump shall be OPERABLE in MODE 4 when the temperature of one or more of the RCS cold legs is less than or equal to 312'F, Mode 5, or Mode 6 when the head is on the reactor vessel.
SALEM - UNIT 2                        3/4 5-7                 Amendment No. 258

EMERGENCY CORE COOLING SYSTEMS ECCS SUBSYSTEMS - Tavq < 350&deg;F SURVEILLANCE REQUIREMENTS 4.5.3.1 The ECCS subsystem shall be demonstrated OPERABLE per applicable Surveillance Requirements of 4.5.2.
4.5.3.2 All safety injection pumps and centrifugal charging pumps, except the above required OPERABLE pump, shall be demonstrated to be inoperable in accordance with the Surveillance Frequency Control Program while in MODE 4 and the temperature of one or more of the RCS cold legs is less than or equal to 312 0 F, MODE 5, or MODE 6 when the head is on the reactor vessel by either of the following methods:
: a.      By verifying that the motor circuit breakers have been removed from their electrical power supply circuits or,
: b.      By verifying that the pump is in a recirculation flow path and that two independent means of preventing RCS injection are utilized.
SALEM - UNIT 2                                  3/4 5-8                         Amendment No. 282

EMERGENCY CORE COOLING SYSTEMS SEAL INJECTION FLOW LIMITING CONDITION FOR OPERATION 3.5.4 Reactor coolant pump seal injection flow shall be -40 gpm with centrifugal charging pump discharge header pressure > 2430 psig and the charging flow control valve full open.
APPLICABILITY: MODES 1, 2, and 3 ACTION:
With seal injection flow not within the limit, adjust manual seal injection throttle valves to give a flow within the limit with the charging pump discharge pressure > 2430 psig and the charging flow control valve full open within 4 hours, or be in at least HOT STANDBY within the next 6 hours and in HOT SHUTDOWN within the following 6 hours.
SURVEILLANCE REQ.IREMENTS 4.5.4 In accordance with the Surveillance Frequency Control Program, verify manual seal injection throttle valves are adjusted to give a flow within the limit with centrifugal charging pump discharge header pressure > 2430 psig, and the charging flow control valve full open.
The provisions of Specification 4.0.4 are not applicable for entry into Mode 3. This exemption is allowed for up to 4 hours after the Reactor Coolant System pressure stabilizes at 2235 +/- 20 psig.
SALEM - UNIT 2                                  3/4 5-8a                          Amendment No. 282

EMERGENCY CORE COOLING SYSTEMS REFUELING WATER STORAGE TANK LIMITING CONDITION FOR OPERATION 3.5.5 The refueling water storage tank (RWST) shall be OPERABLE with:
: a.      A contained volume of between 364,500 and 400,000 gallons of borated water.
: b.      A boron concentration of between 2,300 and 2,500 ppm, and
: c.      A minimum water temperature of 35 0 F.
APPLICABILITY: MODES 1, 2, 3 and 4.
ACTION:
With the refueling water storage tank inoperable, restore the tank to OPERABLE status within 1 hour or be in at least HOT STANDBY within 6 hours and in COLD SHUTDOWN within the following 30 hours.
SURVEILLANCE REQUIREMENTS 4.5.5 The RWST shall be demonstrated OPERABLE:
: a.      In accordance with the Surveillance Frequency Control Program by:
: 1.      Verifying the water level in the tank, and
: 2.      Verifying the boron concentration of the water.
: b.      In accordance with the Surveillance Frequency Control Program by verifying the RWST temperature when the outside air temperature is < 35&deg;F.
SALEM - UNIT 2                                 3/4 5-9                     Amendment No. 282

3/4.6 CONTAINMENT SYSTEMS 3/4.6.1 PRIMARY CONTAINMENT CONTAINMENT INTEGRITY LIMITING CONDITION FOR OPERATION 3.6.1.1 Primary CONTAINMENT INTEGRITY shall be maintained.
APPLICABILITY: MODES 1, 2, 3 and 4.
ACTION:
Without primary CONTAINMENT INTEGRITY, restore CONTAINMENT INTEGRITY within one hour or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
SURVEILLANCE REQUIREMENTS 4.6.1.1 Primary CONTAINMENT INTEGRITY shall be demonstrated:
al. In accordance with the Surveillance Frequency Control Program by verifying that each containment manual valve or blind flange that is located outside containment and required to be closed during accident conditions is closed, except for containment isolation valves that are open under administrative controls. Valves and blind flanges in high radiation areas may be verified by use of administrative controls.
a2. Prior to entering Mode 4 from Mode 5 if not performed within the last 92 days by verifying that each containment manual valve or blind flange that is located inside containment and required to be closed during accident conditions is closed, except for containment isolation valves that are open under administrative controls. Valves and blind flanges in high radiation areas may be verified by use of administrative controls.
: b.      By verifying that each containment air lock is OPERABLE per Specification 3.6.1.3.
: c.      After each closing of a penetration subject to Type B testing, except containment air locks, if opened following a Type A or B test, by leak rate testing in accordance with the Containment Leakage Rate Testing Program.
: d.      In accordance with the Surveillance Frequency Control Program by verifying that the surveillance requirements of 4.6.2.3.a are met for penetrations associated with the containment fan coil units.
: e.      In accordance with the Surveillance Frequency Control Program by verifying that the surveillance requirements of 4.6.2.3.d are met for penetrations associated with the containment fan coil units.
SALEM - UNIT 2                                  3/4 6-1                         Amendment No. 282

CONTA:*MSNT   SYSSEMS
=:NTAkZINMNT  LZAKAGE L:MIT:NG C:NDITZZN FOR OPERATON 3.6.1.2    :intairunent leakage rates shall be lmited  to:
: a. An overall integrated leakage rate (Type A test) in accordance with :te Containment Leakage Rate Testing Program.
: b. A :ombined leakage rate in accordance with the Containment Leakage Rats Testing Program for all penetrations and valves subject to Type B and tests.
APPLICABILITY:   MODES 1, 2,  3 and 4.
ACTION:
With eitner (a) the measured overall integrated containment leakage rate (Type A test) not in accordance with the Containment Leakage Rate Testing Program or (b) with the measured combined leakage rate for all penetrations and valves sub)ect to
 *Tpes 8 and C tests not in accordance with the Containment Leakage Rate Testing Program, restore the leakage rate(s) to within the lisit(s)    prioe to increasing the Reactor Coolant System temperature above 200*F.
StMRVE ILZCE REQUIREMNTS 4.6.1.2    The containment leakage rates shall be demonstrated as follows:
A. Type A tests shall be in accordance with the Containment Leakage Rate Testing Program.
: b. Type a and C tests shall be conducted in accord&nce with the Containment Leakage Rate Testing Progqa*.
: a. Air locks shall be tested and deeonstrated OPERABLZ in accordance with the Containment Leakage Rate Testing Program.
sxUM - '-"NIT 2                        3/4 6-2       Amendment No. 188

PAGZ 3/4 6-3 IS INTENTIONA&LLY ELAM4 SALEM - UNIT 2              3/4 6-3           Amendment No. 166

CONTAINMENT SYSTEMS CONTAINMENT AIR LOCKS LIMITING CONDITION FOR OPERATION 3.6.1.3       Each containment air lock shall be OPERABLE with:
: a. Both doors closed except when the air lock is being used for normal transit entry and exit through the containment, then at least one air lock door shall be closed, and:
: b. An overall air lock leakage rate in      accordance with the Containment Leakage Rate Testing Program.
APPLICABILITY:        MODES 1, 2,  3, and 4 ACTION:
Notes (1) Entry and exit is    permissible to perform repairs on the affected air lock components.
(2)   Separate condition entry is   allowed for each air lock.
(3)    Required ACTIONS a.1, a.2, and a.3 are not applicable if both doors in the same air lock are inoperable and condition c. is entered.
(4)   Required ACTIONS b.l, b.2, and b.3 are not applicable if both doors in the same air lock are inoperable and condition c. is entered.
(5)   Enter applicable Conditions and required Actions of LCO 3.6.1, "Primary Containment," when air lock leakage results in exceeding the overall containment leakage rate.
: a. One or more containment air locks with one containment airlock door inoperable:
: 1.      Verify the OPERABLE door is    closed in  the affected air lock within 1 hour, and:
: 2.      Lock the OPERABLE door closed in     the affected air lock within 24 hours, and:
: 3.      Verify the OPERABLE door is locked closed in the affected air lock once per 31 days. Entry and exit is permissible for 7 days (from initial LCO entry) under administrative controls if one door is inoperable in each air lock. Air lock doors in high radiation areas may be verified locked closed by administrative means.
: b. One or more containment air locks with only the containment air lock interlock mechanism inoperable.
: 1.      Verify an OPERABLE door is    closed in  the affected air lock within 1 hour, and:
: 2.      Lock an OPERABLE door closed in    the affected air lock within 24.hours, and:
: 3.      Verify an OPERABLE door is locked closed in the affected air lock once per 31 days. Entry and exit of containment is permissible under the control of a dedicated individual for the duration of the entry to ensure only one door is open at a time.       Air lock doors in high radiation areas may be verified locked closed by administrative means.
SALEM - UNIT 2                              3/4 6-4                                     95 Amendment No.1

CONTAINMENT SYSTEMS CONTAINMENT AIR LOCKS LIMITING CONDITION FOR OPERATIONS (Continued)
: c. One or more containment air locks inoperable for reasons other than condition a.
or b.
: 1.      Immediately initiate action to evaluate overall containment leakage per LCO 3.6.1, and:
: 2.      Verify that at least one door is closed in the affected air lock within 1 hour, and:
: 3.      Restore the air lock to OPERABLE status within 24 hours.
: d. If the ACTIONS and associated completion times of a., b., or c. cannot be met, be in Hot Standby within 6 hours and in Cold Shutdown within the following 30 hours.
SURVEILLANCE REQUIREMENTS 4.6.1.3 Each containment air lock shall be demonstrated OPERABLE:
: a. By verifying seal leakage rate in accordance with the Containment Leakage Rate Testing program.
: b. By conducting an overall air lock leakage test in accordance with the Containment Leakage Rate Testing Program.
: c. In accordance with the Surveillance Frequency Control Program by verifying that only one door in each air lock can be opened at a time.
SALEM - UNfT 2                                3/4 6-5                          Amendment No. 282

CONTAINMENT SYSTEMS INTERNAL PRESSURE LIMITING CONDITION FOR OPERATION 3.6.1.4 Primary containment internal pressure shall be maintained between -1.5 and +0.3 psig.
APPLICABILITY: MODES 1, 2, 3 and 4.
ACTION:
With the containment internal pressure outside of the limits above, restore the internal pressure to within the limits within 1 hour or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
SURVEILLANCE REQUIREMENTS 4.6.1.4 The primary containment internal pressure shall be determined to be within the limits in accordance with the Surveillance Frequency Control Program.
SALEM - UNIT 2                                   3/4 6-6                     Amendment No. 282

CONTAINMENT SYSTEMS AIR TEMPERATURE LIMITING CONDITION FOR OPERATION 3.6.1.5 Primary containment average air temperature shall not exceed 120'F.
APPLICABILITY: MODES 1, 2, 3 and 4.
ACTION:
With the containment average air temperature greater than 120'F, reduce the average air temperature to within the limit within 8 hours, or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
SURVEILLANCE REQUIREMENTS 4.6.1.5 Verify containment average air temperature is within limit in accordance with the Surveillance Frequency Control Program.
SALEM - UNIT 2                                 3/4 6-7                       Amendment No. 282

CONTAINMENT SYSTEMS CONTAINMENT STRUCTURAL INTEGRITY LIMITING CONDITIONS FOR OPERATION 3.6.1.6 The structural integrity of the containment shall be maintained at a level consistent with the acceptance criteria in Specification 4.6.1.6.1.
APPLICABILITY:   MODES 1, 2, 3 and 4.
ACTION:
With the structural integrity of the containment not conforming to the above requirements, restore the structural integrity to within the limits within 24 hours or be in at least HOT STANDBY within the next 6 hours and in COLD SNUTDOWN within the following 30 hours.
SURVEILLANCE REQUIREMENTS 4.6.1.6.1 Containment Surfaces The structural integrity of the exposed accessible interior and exterior surfaces of the containment, including the liner plate, shall be determined in accordance with the Containment Leakage Rate Testing Program 4.6.1 . 6.2 Reports Any abnormal degradation of the containment structure detected during the above required inspections shall be evaluated for reportability pursuant to 10CFR50.72 and 10CFR50.73. The evaluation shall be documented and shall include a description of the condition of the concrete, the inspection procedure, the tolerances on cracking, and the corrective action taken.
SALEM - UNIT 2                        3/4 6-8    Amendment No. 206

This page left intentionally blank.
Note that the elements of TS 3.6.1.7 and 4.6.1.7 were relocated to TS 3/4.6.3.
SALEM - UNIT 2                     3/4 6-9                     Amendment No. 260

3/4.6.2 DEPRESSURIZATION AND COOLING SYSTEMS CONTAINMENT SPRAY SYSTEM LIMITING CONDITION FOR OPERATION 3.6.2.1 Two independent containment spray systems shall be OPERABLE with each spray system capable of taking suction from the RWST and transferring suction to the RHR pump discharge.
APPLICABILITY: MODES 1,2, 3 and 4.
ACTION:
With one containment spray system inoperable, restore the inoperable spray system to OPERABLE status within 72 hours or be in at least HOT STANDBY within the next 6 hours; restore the inoperable spray system to OPERABLE status within the next 48 hours or be in COLD SHUTDOWN within the following 30 hours.
SURVEILLANCE REQUIREMENTS 4.6.2.1 Each containment spray system shall be demonstrated OPERABLE:
: a.      In accordance with the Surveillance Frequency Control Program by verifying that each valve (manual, power operated or automatic) in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position.
: b. By verifying, that on recirculation flow, each pump develops a differential pressure of greater than or equal to 204 psid when tested pursuant to the Inservice Testing Program.
: c. In accordance with the Surveillance Frequency Control Program during shutdown, by:
: 1. Verifying that each automatic valve in the flow path actuates to its correct position on a Containment High-High pressure test signal.
: 2.      Verifying each spray pump starts automatically on a Containment High-High pressure test signal.
: d. Following activities that could result in nozzle blockage, either evaluate the work performed to determine the impact to the containment spray system, or perform an air or smoke flow test through each spray header and verifying each spray nozzle is unobstructed.
SALEM - UNIT 2                                 3/4 6-10                        Amendment No. 282

CONTAINMENT SYSTEMS SPRAY ADDITIVE SYSTEM LIMITING CONDITION FOR OPERATION 3.6.2.2 The spray additive system shall be OPERABLE with:
: a. A spray additive tank containing a volume of between 2568 and 4000 gallons of between 30 and 32 percent by weight NaOH solution, and
: b. Two spray additive eductors each capable of adding NaOH solution from the chemical additive tank to a containment spray system pump flow.
APPLICABILITY: MODES 1, 2, 3 and 4.
ACTION:
With the spray additive system inoperable, restore the system to OPERABLE status within 72 hours or be in at least HOT STANDBY within the next 6 hours; restore the spray additive system to OPERABLE status within the next 48 hours or be in COLD SHUTDOWN within the following 30 hours.
UIJRVEILLANCE REQUIREMENTS 4.6.2.2 The spray additive system shall be demonstrated OPERABLE:
: a. In accordance with the Surveillance Frequency Control Program by verifying that each valve (manual, power operated or automatic) in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position.
: b. In accordance with the Surveillance Frequency Control Program by:
: 1.      Verifying the solution level in the tank, and
: 2.      Verifying the concentration of the NaOH solution by chemical analysis.
: c. In accordance with the Surveillance Frequency Control Program during shutdown, by verifying that each automatic valve in the flow path actuates to its correct position on a Containment High-High pressure test signal.
: d. In accordance with the Surveillance Frequency Control Program by:
: 1.      Verifying a NaOH solution flow rate of 12.0 + 3.0 gpm from the spray additive tank through sample valve 2CS61 with the spray additive tank at 2.5 +/- 0.5 psig and SALEM - UNIT 2                                3/4 6-11                         Amendment No. 282

CONTAINMENT SYSTEMS SPRAY ADDITIVE SYSTEM SURVEILLANCE REQUIREMENTS (Continued)
: 2. Verifying that the spray additive tank eductor flow will be 35 +/- 3.5 gpm to each containment spray system. Testing may be performed by measuring the flow of borated water from the RWST through the installed 2" test line and Valve CS31; using this test line up with the spray pump operating in the recirculation mode and the RWST level at 41 feet + 0.5 feet, the measured flow shall be 57 gpm +
5.7 gpm.
SALEM - UNIT 2                 3/4 6-11a,            Amendment No. 102,

CONTAINMENT SYSTEMS CONTAINMENT COOLING SYSTEM LIMITING CONDITION FOR OPERATION 3.6.2.3   Five containment cooling fans shall be OPERABLE.
APPLICABILITY:     MODES 1, 2 and 3.
ACTION:
: a. With one or two of the above required containment cooling fans inoperable, restore the inoperable cooling fan(s) to OPERABLE status within 7 days or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
: b. With three or more of the above required containment cooling fans inoperable, restore at least three cooling fans to OPERABLE status within 1 hour or be in at least HOT STANDBY WITHIN the next 6 hours and in COLD SHUTDOWN within the following 30 hours. Restore the remaining inoperable cooling fans to OPERABLE status within 7 days of initial    loss or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
SURVEILLANCE REQUIREMENTS 4.6.2.3   Each containment cooling fan shall be demonstrated OPERABLE:
SALEM - UNIT 2                 3/4 6-12              Amendment No. 248

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)
: a.      In accordance with the Surveillance Frequency Control Program b,:
: 1. Verifying the water level in each service water accumulator vessel is greater than or equal to 226 inches and less than or equal to 252 inches.
: 2.      Verifying the temperature in each service water accumulator vessel is greater than or equal to 55 0 F and less than or equal to 951F.
: 3. Verifying the nitrogen cover pressure in each service water accumulator vessel is greater than or equal to 135 psig and less than or equal to 160 psig.
: b.      In accordance with the Surveillance Frequency Control Program by:
: 1. Starting (unless already operating) each fan from the control room in low speed.
: 2.      Verifying that each fan operates for at least 15 minutes in low speed.
: 3.      Verifying a cooling water flow rate of greater than or equal to 1300 gpm to each cooler.
: c.      In accordance with the Surveillance Frequency Control Program by verifying that on a safety injection test signal:
: 1. Each fan starts automatically in low speed.
: 2.      The automatic valves and dampers actuate to their correct positions and that the cooling water flow rate to each cooler is greater than or equal to 1300 gpm.
: d. In accordance with the Surveillance Frequency Control Program by verifying that on a loss of offsite power test signal, each service water accumulator vessel discharge valve response time is within limits.
SALEM - UNIT 2                             3/4 6-13                         Amendment No. 282

CONTAINMENT SYSTEMS 3/4.6.3    CONTAINMENT ISOLATION VALVES LIMITING CONDITION FOR OPERATION 3.6.3    Each containment isolation valve shall be OPERABLE.
APPLICABILITY:     MODES 1, 2, 3 and 4.
ACTION:
NOTE 1 Penetration flow paths, except for the containment purge valves, may be unisolated intermittently under administrative controls.
Note 2 A containment purge valve is not a required containment isolation valve when its flow path is isolated with a testable blind flange tested in accordance with SR 4.6.1.2.b. The required containment purge supply and exhaust isolation valves shall be closed. (Valves immobilized in shut position with control air to valve operators isolated and tagged out of service).
NOTE 3 The containment pressure-vacuum relief isolation valves may be opened on an intermittent basis, under administrative control, as necessary to satisfy the requirement of Specification 3.6.1.4.
: 1. With one or more of the containment isolation valve(s) inoperable, maintain at least one isolation valve OPERABLE in each affected penetration that is open and either:
: a. Restore the inoperable valve(s) to OPERABLE status within 4 hours, or
: b. Isolate each affected penetration within 4 hours by use of at least one deactivated automatic valve secured in the isolation position, or
: c. Isolate each affected penetration within 4 hours by use of at least one closed manual valve or blind flange; or
: d. Be in  at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
: 2. With one required containment purge supply and/or exhaust isolation valve open, close the open valve(s) within one hour or be in at least HOT STANDBY within the next 6 hours and in    COLD SHUTDOWN within the following 30 hours.
SURVEILLANCE REQUIREMENTS 4.6.3.1    DELETED SALEM - UNIT 2                          3/4 6-14               Amendment No. 260

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) 4.6.3.2 Each containment isolation valve shall be demonstrated OPERABLE during the COLD SHUTDOWN or REFUELING MODE in accordance with the Surveillance Frequency Control Program by:
: a.      Verifying that on a Phase A containment isolation test signal, each Phase A isolation valve actuates to its isolation position.
: b.      Verifying that on a Phase B containment isolation test signal, each Phase B isolation valve actuates to its isolation position.
: c.      NOT USED
: d.      Verifying that on a Containment Purge and Pressure-Vacuum Relief isolation test signal, each required Purge and each Pressure-Vacuum Relief valve actuates to its isolation position.
: e.      Verifying that the Containment Pressure-Vacuum Relief Isolation valves are limited to _ 600 opening angle.
4.6.3.3 In accordance with the Surveillance Frequency Control Program, verify that on a main steam isolation test signal, each main steam isolation valve actuates to its isolation position.
4.6.3.4 The isolation time of each power operated or automatic containment isolation valve shall be determined to be within its limit when tested pursuant to the Inservice Testing Program.
4.6.3.5 Each required containment purge isolation valve shall be demonstrated OPERABLE within 24 hours after each closing of the valve, except when the valve is being used for multiple cyclings, then in accordance with the Surveillance Frequency Control Program, by verifying that when the measured leakage rate is added to the leakage rates determined pursuant to Specification 4.6.1.2.b for all other Type B and C penetrations, the combined leakage rate is less than or equal to 0.60La.
4.6.3.6 A pressure drop test to identify excessive degradation of resilient valve seals shall be conducted on the:
: a.      Required Containment Purge Supply and Exhaust Isolation Valves in accordance with the Surveillance Frequency Control Program.
: b.      Deleted.
4.6.3.7 The required containment purge supply and exhaust isolation valves shall be determined closed in accordance with the Surveillance Frequency Control Program.
SALEM - UNIT 2                                  3/4 6-15                      Amendment No. 282

PAGES 3/4 6-16 THROUGH 3/4 6-22 ARE INTENTIONALLY BLANK.
SALEM - UNIT 2            3/4 6-16 through 6-22              Amendment No. 264

3/4.7 PLANT SYSTEMS 3/4.7.1 TURBINE CYCLE SAFETY VALVES LIMITING CONDITION FOR OPERATION 3.7.1.1 All main steam line code safety valves (MSSVs) associated with each steam generator shall be OPERABLE with lift settings as specified in Table 3.7-4.
APPLICABILITY: MODES 1, 2 and 3.
ACTION:
: a. With one or two main steam line code safety valves inoperable in one or more steam generators, operation in Modes 1, 2 and 3 may proceed provided, that within 4 hours, either the inoperable valve is restored to OPERABLE status or reduce power to less than or equal to the applicable percent of RATED THERMAL POWER per Table 3.7-1; otherwise, be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
: b. With three main steam line code safety valves inoperable in one or more steam generators, operation in Modes 1, 2 and 3 may proceed provided, that within 4 hours, either the inoperable valves are restored to OPERABLE status or reduce power to less than or equal to the applicable percent of RATED THERMAL POWER per Table 3.7-1 and within 36 hours, reduce the Power Range Neutron Flux High trip setpoint to less than or equal to the RATED THERMAL POWER per Table 3.7-1; otherwise, be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
SURVEILLANCE REQUIREMENTS 4.7.1.1 Verify each required MSSV lift setpoint per Table 3.7-4. No additional Surveillance Requirements other than those required by the Inservice Testing Program.
SALEM - UNIT 2                                 3/4 7-1                       Amendment No. 279

TABLE 3.7-1 MAXIMUM ALLOWABLE POWER WITH INOPERABLE STEAM LINE SAFETY VALVES Maximum Number of Inoperable Safety                          Maximum Allowable Power*
Valves on Any Operating Steam Generator                      (Percent of RATED THERMAL POWER) 1                                                      87 2                                                      58                       I 3                                                      39
* The values do not provide any allowance for calorimetric errori SALEM - UNIT 2                                         3/4 7-2                       Amendment No. 259

THIS PAGE INTENTIONALLY BLANK                   I SALEM - UNIT 2             3/4 7-3           Amendment No. 225

TABLE 3.7-4 STEAM LINE SAFETY VALVES PER LOOP VALVE NUMBER                                    LIFT SETTING (. 3%)* ORIFICE SIZE (sq. inches) I Loop A    Loop B     Loop C      Loop D
: a. 21MS11    22MS11     23MS11      24MS11       1125 psig             16.0
: b. 21MS12    22MS12     23MS12      24MS12       1120 psig             16.0 C. 21MS13    22MS13     23MS13      24MS13       1110 psig             16.0
: d. 21MS14    22MS14      23MS14     24MS14       1100 psig             16.0
: e. 21MS15    22MS15     23MS15      24MS15       1070 psig             16.0 Following testing  the lift setting    shall be reset to within +/- 1%.
I 22 5 SALEM - UNIT 2                          3/4 7-4                 Amendment No.

PLANT SYSTEMS AUXILIARY FEEDWATER SYSTEM LIMITING CONDITION FOR OPERATION 3.7.1.2 At least three independent steam generator auxiliary feedwater pumps and associated manual activation switches in the control room and flow paths shall be OPERABLE with:
: a. Two feedwater pumps, each capable of being powered from separate vital busses, and
: b. One feedwater pump capable of being powered from an OPERABLE steam supply system.
APPLICABILITY: MODES 1, 2 and 3.
ACTION:
: a. With one auxiliary feedwater pump inoperable, restore the required auxiliary feedwater pumps to OPERABLE status within 72 hours or be in at least HOT STANDBY within the next 6 hours and in HOT SHUTDOWN within the following 6 hours.
: b. With two auxiliary feedwater pumps inoperable be in at least HOT STANDBY within 6 hours and in HOT SHUTDOWN within the following 6 hours.
: c. With three auxiliary feedwater pumps inoperable, immediately initiate corrective action to restore at least one auxiliary feedwater pump to OPERABLE status as soon as possible.
: d. LCO 3.0.4.b is not applicable.
SURVEILLANCE REQUIREMENTS 4.7.1.2 Each auxiliary feedwater pump shall be demonstrated OPERABLE:
: a. In accordance with the Surveillance Frequency Control Program by:
: 1.      Verifying that each non-automatic valve in the flow path that is not locked, sealed or otherwise secured in position, is in its correct position.
: 2.      Verify the manual maintenance valves in the flow path to each steam generator are locked open.
SALEM - UNIT 2                                3/4 7-5                          Amendment No. 282

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)
: b. In accordance with the Surveillance Frequency Control Program by:
: 1. Verify that the developed head of each motor driven pump at the flow test point is greater than or equal to the required developed head.
: 2. Verify that the developed head of the steam driven pump at the flow test point is greater than or equal to the required developed head when the steam generator pressure is > 680 psig. The provisions of Specification 4.0.4 are not applicable provided the surveillance is performed within 24 hours after secondary side pressure is greater than 680 psig.
: c. In accordance with the Surveillance Frequency Control Program by:
: 1. Verifying that each auxiliary feedwater automatic valve that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.
: 2. Verifying that each auxiliary feedwater pump starts automatically on an actual or simulated actuation signal.
The provisions of Specification 4.0.4 are not applicable to the turbine driven auxiliary feedwater pump, provided the surveillance is performed within 24 hours after the secondary steam generator pressure is greater than 680 psig.
SALEM - UNIT 2                              3/4 7-6                        Amendment No. 282

PLANT SYSTEMS AUXILIARY FEED STORAGE TANK LIMITING CONDITION FOR OPERATION 3.7.1.3 The auxiliary feed storage tank (AFST) shall be OPERABLE with a contained volume of at least 200,000 gallons of water.
APPLICABILITY: MODES 1, 2 and 3.
ACTION:
With the auxiliary feed storage tank inoperable, within 4 hours either:
: a.       Restore the AFST to OPERABLE status or be in HOT SHUTDOWN within the next 12 hours, or
: b.      Demonstrate the OPERABILITY of a demineralized water or a fire protection/domestic water storage tank as a backup supply to the auxiliary feedwater pumps and restore the auxiliary feed storage tank to OPERABLE status within 7 days or be in HOT SHUTDOWN within the next 12 hours.
SURVEILLANCE REQUIREMENTS 4.7.1.3.1 The auxiliary feed storage tank shall be demonstrated OPERABLE in accordance with the Surveillance Frequency Control Program by verifying the water level is within its limits when the tank is the supply source for the auxiliary feedwater pumps.
4.7.1.3.2 A demineralized water storage tank shall be demonstrated OPERABLE in accordance with the Surveillance Frequency Control Program by verifying the tank contains greater than or equal to 200,000 gallons of water and by verifying proper alignment of valves for taking suction from this tank when it is the supply source for the auxiliary feedwater pumps.
4.7.1.3.3 A fire protection/domestic water storage tank shall be demonstrated OPERABLE in accordance with the Surveillance Frequency Control Program by verifying the tank contains greater than or equal to 200,000 gallons of water and by verifying proper alignment of valves for taking suction from this tank when it is the supply source for the auxiliary feedwater pumps.
4.7.1.3.4 The Service Water System shall be demonstrated capable of providing a water supply to the Auxiliary Feedwater System in accordance with the Surveillance Frequency Control Program by verifying that the required spool-piece is on-site.
SALEM - UNIT 2                                 314 7-7                         Amendment No. 282

PLANT SYSTEMS ACTIVITY                                                                       9 LIMITING CONDITION FOR OPERATION 3.7.1.4 The specific activity of the secondary coolant system shall be less than or equal to 0.10 yCi/gram DOSE EQUIVALENT 1-131.
APPLICABILITY:  MODES 1, 2, 3, and 4.
ACTION:
With the specific activity of the secondary coolant system greater than 0.10 pCi/gram DOSE EQUIVALENT 1-131, be in at least HOT STANDBY within 6 hours and in COLD SHUTDOWN within the following 30 hours.
SURVEILLANCE REQUIREMENTS 4.7.1.4 The specific activity of the secondary coolant system shall be deter-mined to be within the limit by performance of the sampling and analysis program of Table 4.7-2.
SALEM - UNIT 2            3/4 7 TABLE 4.7-2 SECONDARY COOLANT SYSTEM SPECIFIC ACTIVITY SAMPLE AND ANALYSIS PROGRAM TYPE OF MEASUREMENT AND ANALYSIS                     SAMPLE AND ANALYSIS FREQUENCY
: 1. Gross Activity Determination       In accordance with the Surveillance Frequency Control Program
: 2. Isotopic Analysis for DOSE         a. In accordance with the Surveillance Frequency EQUIVALENT 1-131 Concentration          Control Program, whenever the gross activity determination indicates iodine concentrations greater than 10% of the allowable limit.
: b. In accordance with the Surveillance Frequency Control Program, whenever the gross activity determination indicates iodine concentrations below 10% of the allowable limit.
SALEM - UNIT 2                           3/4 7-9                        Amendment No. 282

PLANT SYSTEMS MAIN STEAM LINE ISOLATION VALVES LIMITING CONDITION FOR OPERATION 3.7.1.5 Each main steam line isolation valve shall be OPERABLE.
APPLICABILITY: MODES 1, 2 and 3.
ACTION:
MODES 1 -      With one main steam line isolation valve inoperable, POWER OPERATION may continue provided the inoperable valve is either restored to OPERABLE status or closed within 4 hours; Otherwise, be in MODE 2 within the next 6 hours.
MODES 2-       With one or more main steam line isolation valve(s) inoperable, subsequent and 3          operation in MODES 2 or 3 may proceed provided;
: a.      The isolation valve(s) is (are) maintained closed, and
: b. The isolation valve(s) is (are) verified closed once per 7 days.
Otherwise, be in MODE 3, HOT STANDBY, within the next 6 hours, and MODE 4, HOT SHUTDOWN, within the following 6 hours.
SURVEILLANCE REQUIREMENTS 4.7.1.5 Each main steam line isolation valve shall be demonstrated OPERABLE by verifying full closure within 5 seconds when tested pursuant to the Inservice Testing Program. The provisions of Specification 4.0.4 are not applicable.
SALEM - UNIT 2                               3/4 7-10                         Amendment No. 279

PLANT SYSTEMS 3/4.7.2 STEAM GENERATOR PRESSURE/TEMPERATURE LIMITATION LIMITING CONDITION FOR OPERATION 3.7.2 The temperatures of both the primary and secondary coolants in the steam generators shall be greater than 707F when the pressure of either coolant in the steam generator is greater than 200 psig.
APPLICABILITY: At all times.
ACTION:
With the requirements of the above specification not satisfied:
: a.       Reduce the steam generator pressure of the applicable side to less than or equal to 200 psig within 30 minutes, and
: b.       Perform an engineering evaluation to determine the effect of the overpressurization on the structural integrity of the steam generator. Determine that the steam generator remains acceptable for continued operation prior to increasing its temperatures above 200 0 F.
SURVEILLANCE REQUIREMENTS 4.7.2 The pressure in each side of the steam generator shall be determined to be less than 200 psig in accordance with the Surveillance Frequency Control Program when the temperature of either the primary or secondary coolant is less than 70 0 F.
SALEM - UNIT 2                                 3/4 7-1 1                        Amendment No. 282

PLANT SYSTEMS 3/4.7.3 COMPONENT COOLING WATER SYSTEM LIMITING CONDITION FOR OPERATION 3.7.3 At least two independent component cooling water loops shall be OPERABLE.
APPLICABILITY: MODES 1, 2, 3 and 4.
ACTION:
With only one component cooling water loop OPERABLE, restore at least two loops to OPERABLE status within 72 hours or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.*
SURVEILLANCE REQUIREMENTS 4.7.3 At least two component cooling water loops shall be demonstrated OPERABLE:
: a.      In accordance with the Surveillance Frequency Control Program by verifying that each valve (manual, power operated or automatic) servicing safety related equipment that is not locked, sealed, or otherwise secured in position, is in its correct position.
The time for completion of repairs to number 22 component cooling water heat exchanger shall be extended from 0700 hours on November 23, 1982 to 1900 hours on November 23, 1982. If repairs are not completed by that time, the unit shall be placed in HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
SALEM - UNIT 2                                3/4 7-12                       Amendment No. 282

PLANT SYSTEMS 3/4.7.4 SERVICE WATER SYSTEM LIMITING CONDITION FOR OPERATION 3.7.4 At least two independent service water loops shall be OPERABLE.
APPLICABILITY: MODES 1, 2, 3 and 4.
ACTION:
With only one service water loop OPERABLE, restore at least two loops to OPERABLE status within 72 hours or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
SURVEILLANCE REQUIREMENTS 4.7.4 At least two service water loops shall be demonstrated OPERABLE:
: a.      In accordance with the Surveillance Frequency Control Program by verifying that each valve (manual, power operated or automatic) servicing safety related equipment that is not locked, sealed, or otherwise secured in position, is in its correct position.
: b.      In accordance with the Surveillance Frequency Control Program during shutdown, by verifying that each automatic valve servicing safety related equipment actuates to its correct position on Safeguards Initiation signal.
SALEM - UNIT 2                                3/4 7-13                       Amendment No. 282

PLANT SYSTEMS 3/4.7.5 FLOOD PROTECTION LIMITING CONDITION FOR OPERATION 3.7.5 Flood protection shall be provided for all safety related systems, components and structures when the water level of the Delaware River exceeds 10.5' Mean Sea Level USGS datum, at the service water intake structure.
APPLICABILITY: At all times.
ACTION:
: a. With the water level at the service water intake structure above elevation 10.5' Mean Sea Level USGS datum, close all watertight doors within 2 hours.
: b. With the water level at the service water intake structure above elevation 11.5' Mean Sea Level USGS datum, be in at least HOT STANDBY within 6 hours and in COLD SHUTDOWN within the following 30 hours.
SURVEILLANCE REQUIREMENTS 4.7.5 The water level at the service water intake structure shall be determined to be within the limits by:
: a. Measurement in accordance with the Surveillance Frequency Control Program when the water level is below elevation 10.5' Mean Sea Level USGS datum, and
: b. Measurement in accordance with the Surveillance Frequency Control Program when the water level is equal to or above elevation 10.5' Mean Sea Level USGS datum.
SALEM - UNIT 2.                               3/4 7-14                       Amendment No. 282

PLANT SYSTEMS 3/4.7.6 CONTROL ROOM EMERGENCY AIR CONDITIONING        SYSTEM LIMITING CONDITION FOR OPERATION 3.7.6    The common control room emergency air conditioning system (CREACS)*
shall be OPERABLE with:
a*. Two independent air conditioning filtration trains       (one from each unit) consisting of:
: 1. Two fans and associated outlet dampers,
: 2. One cooling coil,
: 3. One charcoal adsorber and HEPA filter      array,
: 4. Return air isolation damper.
: b. All other automatic dampers required for operation in       the pressurization or recirculation modes.
: c. The control room envelope intact.
NOTE: The control room envelope         (CRE) boundary may be opened intermittently under administrative control.
APPLICABILITY:     ALL MODES and during movement of irradiated fuel assemblies.
ACTION:      MODES 1, 2,   3, and 4
: a. With one filtration train inoperable, align CREACS for single filtration train operation within 4/hours, and restore the inoperable filtration train to OPERABLE status within 30 days or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
: b.      With CREACS aligned for single filtration train operation and with one of the two remaining fans or associated outlet damper inoperable, restore the inoperable fan or damper to OPERABLE status within 72 hours or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
: c. With the Control Room Envelope boundary inoperable:
: 1. Immediately, initiate action to implement mitigating actions, and
: 2. Within 24 hours, verify mitigating actions ensure CRE occupant exposures to^radiological, chemical, and smoke hazards will not exceed limits., and
: 3. Within 90 days, restore the Control Room Envelope boundary to OPERABLE status, or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
* The CREACS is *a 'shared system -with Salem Unit I SALEM - '-'NIT .2                   31-4 7-15                        Amendment 24o. 269

PLANT SYSTEMS LIMITING CONDITION FOR OPERATION (Continued)
: d. With one or both series isolation damper(s) on a normal Control Area Air Conditioning System (CAACS) outside air intake or exhaust duct inoperable, close the affected duct within 4 hours by use of at least one isolation damper secured in the closed position or be in at least HOT STANDBY within the next 6 hour's and in COLD SHUTDOWN within the following 30 hours. (Refer to ACTION 28.of Table 3.3-6.)
: e. With one or both isolation damper(s) on an outside emergency air conditioning air intake duct inoperable, close the affected duct within 4 hours by use of at least one isolation damper secured in the closed position and restore the damper(s) to OPERABLE status within 7 days or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
: f. With any isolation damper between the normal CAACS and the CREACS inoperable, secure the damper in the closed position within 4 hours or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
MODES 5 and 6 or during movement of irradiated fuel assemblies
: a. With one filtration train inoperable, align CREACS for single filtration train operation within 4 hours, or suspend movement of irradiated fuel assemblies.
: b. With CREACS aligned for single filtration train operation with one
             -of the two remaining fans or associated outlet damper inoperable, restore the fan or damper to OPERABLE status within 72 hours, or
             .suspend movement of irradiated fuel assemblies.
: c. With two filtration trains inoperable, immediately suspend movement of irradiated fuel assemblies.
: d. With the Control Room Envelope boundary inoperable,   immediately suspend movement of irradiated fuel assemblies.
: e. With one or both series isolation damper(s) on a normal CAACS outside air intake or exhaust duct inoperable, immediately suspend movement of irradiated fuel assemblies until the affected duct is closed by use of at least one isolation damper secured in the closed position. (Refer to ACTION 28 of Table 3.3-6.)
: f. With one or both series isolation damper(s) on an outside emergency air conditioning air intake duct inoperable, immediately suspend movement of irradiated fuel assemblies until the affected duct is closed by use of at least one isolation damper secured in the closed position. To resume movement of irradiated fuel assemblies, at least one emergency air intake duct must be operable on each unit.
: g. Wi-th any isolation damper between the CAACS and the CREACS inoperable, immediately suspend movement of irradia~ted fuel assemblies until the damper is -. losed and secured im the closed position-.
SALEM - 'UNIT 2                        3/4 7-i16                Amendment .No. 269

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS 4.7.6.1 The control room emergency air conditioning system shall be demonstrated OPERABLE:
: a. In accordance with the Surveillance Frequency Control Program by initiating flow through the HEPA filter and charcoal adsorber train(s) and verifying that the train(s) operates with each fan operating for at least 15 minutes.
: b. In accordance with the Surveillance Frequency Control Program or prior to return to service (1) after any structural maintenance on the HEPA filter or charcoal adsorber housings, or (2) following painting, fire or chemical release in any ventilation zone communicating with the system, by:
: 1.       Verifying that the charcoal adsorbers remove a 99% of a halogenated hydrocarbon refrigerant test gas when they are tested in-place while operating the ventilation system at a flow rate of 8000 cfm +/- 10%.
: 2.       Verifying that the HEPA filter banks remove a 99% of the DOP when they are tested in-place while operating the ventilation system at a flow rate of 8000 cfm +/- 10%.
: 3.       Verifying within 31 days after removal from the CREACS unit, that a laboratory test of a sample of the charcoal adsorber, when obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, shows the methyl iodide penetration less than 2.5% when tested in accordance with ASTM D3803-1989 at a temperature of 300C and a relative humidity of 95%.
: c. After every 720 hours of charcoal adsorber operation by verifying within 31 days after removal from the CREACS unit, that a laboratory analysis of a representative carbon sample, when obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, shows a methyl iodide penetration less than 2.5% when tested in accordance with ASTM D3803-1989 at a temperature of 30 0C and a relative humidity of 95%.
: d. In accordance with the Surveillance Frequency Control Program by:
: 1.       Verifying that the pressure drop across the combined HEPA filter and charcoal adsorber bank is - 3.5 inches water gauge while operating the ventilation system at a flow rate of 8000 cfm +/- 10%.
: 2.      Verifying that on a safety injection test signal or control room intake high radiation test signal, the system automatically actuates in the pressurization mode by opening the outside air supply and diverting air flow through the HEPA filter and charcoal adsorber bank.
: 3.       Deleted.
SALEM - UNIT 2                                 3/4 7-17                        Amendment No. 282

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS     (Continued)
: 4. Verifying that on a manual actuation signal, the system will actuate to the required pressurization or recirculation operating mode.
: 5. Verify each CREACS train    has the capability to remove the assumed heat load.
: e. After each complete or partial     replacement of a HEPA filter bank by verifying that the HEPA filter     banks remove &#x17d; 99% of the DOP when they are tested in-place while operating the filter     system at a flow rate of 8000 cfm +/- 10%.
: f. After each complete or partial replacement of a charcoal absorber bank by verifying that the charcoal absorbers remove &#x17d; 99% of a halogenated hydrocarbon refrigerant test gas when they are tested in-place while operating the filter   system at a flow rate of 8000 cfm +/- 10%.
4.7.6.2   Perform required CRE unfiltered air inleakage testing in accordance with the Control Room Envelope Habitability Program (Refer to T.S. 6.17).
SALEM -  UNIT 2                          3/4 7-17a               Amendment No. 269

PLANT SYSTEMS 3/4.7.7 AUXILIARY BUILDING VENTILATION          SYSTEM LIMITING CONDITION FOR OPERATION 3.7.7       At least two supply fans, and three exhaust fans shall be OPERABLE(*)           to maintain the Auxiliary Building at slightly          negative pressure.
-----         ------------------------   NOTE------------------------------------------
The intermittent opening of the Auxiliary Building pressure boundary causing a loss of negative pressure may be performed under administrative controls.
APPLICABILITY:        At all  times.
ACTION:
Modes 1 thru 4 a)    With one supply fan and/or one exhaust fan inoperable, restore the fan(s) to OPERABLE status within 14 days or be in HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
b)    With two supply and/or two exhaust fans inoperable restore at least one inoperable supply and two exhaust fans to operable status within 24 hours or be in HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
c) With the Auxiliary Building pressure not maintained slightly negative, restore the building to slightly       negative pressure within the next 4 hours or be in HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
During CORE ALTERATIONS d)    With the Auxiliary Building pressure not maintained slightly negative, restore the Auxiliary Building to slightly         negative pressure within the next 4 hours or suspend all        operations involving CORE ALTERATIONS.
At all       times e)    With the Auxiliary Building pressure not maintained slightly negative, suspend all      operations involving radioactive gaseous releases via the Auxiliary Building immediately.
(*)    One of the supply fans may be considered OPERABLE with its          auto start    circuit   administratively controlled (removed form service) to prevent more than one supply fan from operating at any time.
SALEM - UNIT 2                         3/4 7-18                         Amendment No. 252

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS 4.7.7 The above required Auxiliary Building Ventilation System shall be demonstrated OPERABLE:
a)    In accordance with the Surveillance Frequency Control Program by verifying negative pressure in the Auxiliary Building.
b)     In accordance with the Surveillance Frequency Control Program by starting each fan, from the control room, each fan operates for at least 15 minutes.
c)     In accordance with the Surveillance Frequency Control Program by verifying that the system starts following a Safety Injection Test Signal.
SALEM - UNIT 2                              3/4 7-19                       Amendment No. 282

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS S
THIS PAGE LEFT BLANK INTENTIONALLY SALEM - UNIT 2                          3/4 7-20         Amendment No.252

PLANT SYSTEMS 3/4.7.8 SEALED SOURCE CONTAMINATION LIMITING CONDITION FOR OPERATION 3.7.8 Each sealed source containing radioactive material either in excess of 100 microcuries of beta and/or gamma emitting material or 5 microcuries of alpha emitting material shall be free of greater than or equal to 0.005 microcuries of removable contamination.
APPLICABILITY: At all times.
ACTION:
: a. With a sealed source having removable contamination in excess of the above limits, immediately withdraw the sealed source from use and:
: 1.       Either decontaminate and repair the sealed source, or
: 2.        Dispose of the sealed source in accordance with Commission Regulations.
: b. The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REQUJIREMENTS 4.7.8.1 Test Requirements - Each sealed source shall be tested for leakage and/or contamination by:
: a.      The licensee, or
: b.      Other persons specifically authorized by the Commission or an Agreement State.
The test method shall have a detection sensitivity of at least 0.005 microcuries per test sample.
4.7.8.2 Test Frequencies - Each category of sealed sources (excluding startup sources and fission detectors previously subjected to core flux) shall be tested at the frequency described below.
: a.      Sources in use - In accordance with the Surveillance Frequency Control Program for all sealed sources containing radioactive materials:
SALEM - UNIT 2                                 3/4 7-21                        Amendment No. 282

PLANT SYSTEMS 4
SURVEILLANCE REQUIREMENTS (Continued)
: 1. With a half-life greater than 30 days (excluding Hydrogen 3),
and
: 2. In any form other than gas.
: b. Stored sources not in use - Each sealed source and fission detector shall be tested prior to use or transfer to another licensee unless tested within the previous six months. Sealed sources and fission detectors transferred without a certificate indicating the last test date shall be tested prior to being placed into use.
: c. Startup sources and fission detectors - Each sealed startup source and fission detector shall be tested within 31 days prior to being subjected to core flux and following repair or maintenance to the source or detector.
4.7.8.3 Reports - A report shall be prepared and submitted to the Commission on an annua     asis if sealed source or fission detector leakage tests reveal the presence of greater than or equal to 0.005 microcuries of removable contamination.
SALEM - UNIT 2                        3/4 7-22

PLANT SYSTEMS 3/4.7.9 SNUBBERS LIMITING CONDITION FOR OPERATION 3.7.9 All snubbers shall be OPERABLE.
APPLICABILITY: MODES 1, 2, 3 and 4. (MODES 5 and 6 for snubbers located on systems required OPERABLE in those MODES).
ACTION:
With one or more snubbers inoperable, within 72 hours, replace or restore the inoperable snubber(s) to OPERABLE status and perform an engineering evaluation per Specification 4.7.9 on the supported component or declare the supported system inoperable and follow appropriate ACTION statement for that system.
SURVEILLANCE REQUIREMENTS 4.7.9 Each snubber shall be demonstrated OPERABLE by performance of the Snubber Testing Program for examination, testing and service life monitoring of snubbers.
SALEM - UNIT 2                             3/4 7-23                        Amendment No. 284

Pages 3/4 7-25 through 3/4 7-27 have been deleted.
SALEM - UNIT 2                      3/4 7-24                      Amendment No. 284

i PLANT SYSTEMS 3/4.7.10 CHILLED WATER SYSTEM     - AUXILIARY BUILDING SUBSYSTEM LIMITING CONDITION FOR OPERATION 3.7.10 The chilled water system loop which services the safety-related loads in the Auxiliary Building shall be OPERABLE with:
: a.      Three OPERABLE chillers
: b.      Two OPERABLE chilled water pumps APPLICABILITY: ALL MODES and during movement of irradiated fuel assemblies.
ACTION:    MODES 1, 2,  3, and 4
: a. With one chiller inoperable:
: 1. Remove the appropriate non-essential heat loads from the chilled water system within 4 hours and;
: 2. Restore the chiller to OPERABLE status within 14 days or;
: 3. Be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
: b. With two chillers inoperable:
: 1. Remove the appropriate non-essential heat loads from the chilled water system within 4 hours and;
: 2. Align the control room emergency air conditioning system (CREACs) for single filtration operation using the Salem Unit 1 train within 4 hours and;
: 3. Restore at least one chiller to OPERABLE status within 72 hours or;
: 4. Be in at least HOT STANDBY within the next 6 hours and in' COLD SHUTDOWN within the following 30 hours.
: c. With one chilled water pump inoperable, restore the chilled water pump to OPERABLE status within 7 days or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
SALEM - UNIT 2                    3/4 7-28          Amendment No. 206

PLANT SYSTEMS LIMITING CONDITION FOR OPERATION ACTION: MODES 5 and 6 or during movement of irradiated fuel assemblies.*
: a.      With one chiller inoperable:
: 1.       Remove the appropriate non-essential heat loads from the Chilled Water System within 4 hours and;
: 2.       Restore the chiller to OPERABLE status within 14 days or;
: 3.       Suspend CORE ALTERATIONS and movement of irradiated fuel assemblies.
: b.      With two chillers inoperable:
: 1.       Remove the appropriate non-essential heat loads from the chilled water system within 4 hours and;
: 2.       Align the control room emergency air conditioning system (CREACs) for single filtration operation using the Salem Unit 1 train within 4 hours and;
: 3.       Restore at least one chiller to OPERABLE status within 72 hours or;
: 4.       Suspend CORE ALTERATIONS and movement of irradiated fuel assemblies.
: c.      With one chilled water pump inoperable, restore the chilled water pump to OPERABLE status within 7 days or suspend CORE ALTERATIONS and movement of irradiated fuel assemblies.
SURVEILLANCE REQUIREMENTS 4.7.10 The chilled water loop which services the safety-related loads in the Auxiliary Building shall be demonstrated OPERABLE:
: a.      In accordance with the Surveillance Frequency Control Program by verifying that each manual valve in the chilled water system flow path servicing safety related components that is not locked, sealed, or otherwise secured in position, is in its correct position.
: b.      In accordance with the Surveillance Frequency Control Program, by verifying that each automatic valve actuates to its correct position on a Safeguards Initiation signal.
: c.      in accordance with the Surveillance Frequency Control Program by verifying that each chillers starts and runs.
During Modes 5 and 6 and during movement of irradiated fuel assemblies, chilled water components are not considered to be inoperable solely on the basis that the backup emergency power source, diesel generator, is inoperable.
SALEM - UNIT 2                                    314 7-29                         Amendment No. 282

PLANT SYSTEMS 3/4.7.11 FUEL STORAGE POOL BORON CONCENTRATION LIMITING CONDITION FOR OPERATION 3.7,11 The fuel storage pool boron concentration shall be - 800 ppm APPLICABILITY: When fuel assemblies are stored in the fuel storage pool and a fuel storage pool verification has not been performed since the last movement of fuel assemblies in the fuel storage pool.
ACTION:
With fuel storage pool boron concentration not within limit:
: a. Immediately suspend movement of fuel assemblies in the fuel storage pool and
: b. Initiate action to:
: 1.       immediately restore fuel storage pool boron concentration to within limit or
: 2.       immediately perform a fuel storage pool verification.
: c. The provisions of Specification 3.0.3 is not applicable.
SURVEILLANCE REQUIREMENTS 4.7.11 Verify the fuel storage pool boron concentration is within limit in accordance with the Surveillance Frequency Control Program.
SALEM - UNIT 2                                 3/4 7-30                       Amendment No. 282

PLANT SYSTEMS 3/4.7.12      FUEL ASSEMBLY STORAGE IN THE SPENT FUEL POOL LIMITING CONDITION FOR OPERATION 3.7.12       The combination of initial    enrichment, burnup, and Integral Fuel Burnable Absorber (IFBA) of each fuel assembly stored in Region 1 or Region 2, shall be within the acceptable limits described in the surveillance requirements below.
APPLICABILITY:      When any fuel assembly is     stored in Region 1 or Region 2 of the spent fuel storage pool.
ACTION:
If the requirements of the LCO are not met:
: a. Immediately verify the fuel storage boron concentration meets the requirements of TS 3.7.11 and
: b. Immediately initiate action to move the non-complying fuel assembly to a location that complies with the surveillance requirements.
: c. The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REQUIREMENTS 4.7.12.1    -Prior to storing fuel assemblies in Region 1, verify by administrative means that the fuel assemblies meet oneof the following storage constraints:
: a. Unirradiated fuel assemblies with a maximum enrichment 'of 4.25 wt%       U-235 have unrestricted storage.
: b. Unirradiated fuel assemblies with enrichments greater than 4.25 wt% U-235 and less than or equal to 5.0 wt% U-235, that do not contain IFBA pins, may only be stored in the peripheral cells facing the concrete wall.
: c. Unirradiated fuel assemblies with enrichments (E) greater than 4.25 wt% U-235 and less than or equal to 5.0 wt% U-235, which contain a minimum number of IFBA pins have unrestricted storage. This minimum number of IFBA pins shall have an equivalent reactivity hold-down which is greater than or equal to the reactivity hold-down associated with N IFBA pins, at a nominal 2.35 mg B-10/linear inch loading (1.5x), determined by the equation below:
N = 42.67    (E -  4.25)
Salem - Unit 2                          3/4 7-31                        Amendment No.258

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS       (continued)
: d. Irradiated fuel assemblies with enrichments (E) greater than 4.25 wt% U-235 and less than or equal to 5.0 wt%, that have attained the minimum burnup (BU) as determined by the equation below, have unrestricted storage.
BU, (MWD/kg U) = -26.212 + 6.1677E 4.7.12.2     Prior to storing fuel assemblies in Region 2, verify by administrative means that the fuel assemblies meet one of the following storage constraints:
: a. Unirradiated fuel assemblies with a maximum enrichment of 5.0 wt%
U-235 may be stored in a checkerboard pattern with intermediate cells containing only water or non-fissile bearing material.
: b. Unirradiated fuel assemblies with a maximum enrichment (E) of 5.0 wt% U-235 may be stored in the central cell of any 3x3 array of cells provided the surrounding eight cells are empty or contain fuel assemblies that have attained the minimum burnup (BU) as determined by the equation below.
BU  (MWD/kg U)    = -15.48 + 17.80E -  0.7038E 2 In this configuration, none of the nine cells in any 3x3 array shall be common to cells in any other similar 3x3 array.         Along the rack periphery, the concrete wall is equivalent to 3 outer cells in a 3x3 array.
: c. Irradiated fuel assemblies with a maximum enrichment (E) of 5.0 wt%
U-235 that have attained the minimum burnup (BU) as determined by the equation below, have unrestricted storage.
BU (MWD/kg U) = -32.06 + 25.21E - 3.723E 2     + 0.3535E 3
: d. Irradiated fuel assemblies with a maximum enrichment (E) of 5.0 wt%
U-235 that have attained the minimum burnup (BU) as determined by the equation below, may be stored in a peripheral cell facing the concrete wall.
BU  (MWD/kg   U) = -25.56  + 15.14E - 0.602E 2 Salem - Unit    2                        3/4 7-32                         Amendment No. 244

3/4.8 ELECTRICAL POWER SYSTEMS 3/4.8.1   A.C. SOURCES OPERATING LIMITING CONDITION FOR OPERATION 3.8.1.1 As a-minimum,    the following A.C. electrical power sources shall be OPERABLE:
: a. Two physically independent A.C. circuits between the offsite transmission network and the onsite Class 1E distribution system (vital bus system), and
: b. Three separate and independent diesel generators with:
: 1. Separate day tanks containing a minimum volume of 130 gallons of fuel, and
: 2. A common fuel storage system consisting of two storage tanks, each containing a minimum volume of 23,000 gallons of fuel, and two fuel transfer pumps.
APPLICABILITY:   MODES 1, 2,  3 and 4.
ACTION:
: a. With an independent A.C. circuit of the above required A.C.
electrical power sources inoperable:
: 1. Demonstrate the OPERABILITY of the remaining independent A.C. circuit by performing Surveillance Requirement 4.8.1.1.1.a within one hour and at least once per 8 hours thereafter; and
: 2. Within 24 hours, declare required systems or components with no offsite power available inoperable when a redundant required system or component is inoperable, or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours-; and
: 3. Restore the inoperable independent A.C. circuit to OPERABLE status within 72 hours or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
: b. With one diesel generator of the above required A.C.      electrical power sources inoperable:
: 1. Demonstrate the OPERABILITY of the independent A.C. circuits by performing Surveillance Requirement 4.8.1.1.1.a within 1 hour and at least once per 8 hours thereafter; and
: 2. Within 4 hours, declare required systems or components supported by the inoperable diesel generator inoperable when a required redundant system or component is inoperable, or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours; and SALEM - UNIT 2                         3/4 8-1                   Amendment No. 234

ELECTRICAL POWER SYSTEMS ACTION  (Continued)
: 3. Determine the two remaining OPERABLE diesel generators are not inoperable due to common cause failure or perform Surveillance Requirement 4.8.1.1.2.a.2 within 24 hours. If the diesel generator is inoperable for preventive maintenance, the two remaining OPERABLE diesel generators need not be tested nor the OPERABILITY evaluated; and
: 4. In any case, restore the inoperable diesel generator to OPERABLE status within 72 hours or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
: c. With one independent A.C. circuit and one diesel generator of the above required A.C. electrical power sources inoperable, demonstrate the OPERABILITY of the remaining independent A.C. circuit by performing Surveillance Requirement 4.8.1.1.1.a within one hour and at least once per 8 hours thereafter; demonstrate the OPERABILITY of the remaining OPERABLE diesel generators by performing Surveillance Requirement 4.8.1.1.2.a.2 within 8 hours; restore at least one of the inoperable sources to OPERABLE status within 12 hours or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours. Restore at least two independent A.C.
circuits and three diesel generators to OPERABLE status within 72 hours from the time of initial loss or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
: d. With two of the above required independent A.C. circuits inoperable:
: 1. Demonstrate the OPERABILITY of three diesel generators by performing Surveillance Requirement 4.8.1.1.2.a.2 within 8 hours, unless the diesel generators are already operating; and
: 2. Within 12 hours, declare required systems or components supported by the inoperable offsite circuits inoperable when a required redundant system or component is inoperable, or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours; and
: 3. Restore at least one of the inoperable independent A.C. circuits to OPERABLE status within 24 hours or be in at least HOT STANDBY within the next 6 hours; and
: 4. With only one of the independent A.C. circuits OPERABLE, restore the other independent A.C. circuit to OPERABLE status within 72 hours from time of initial loss or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
SALEM - UNIT 2                       3/4 8-2                  Amendment No. 234

ELECTRICAL POWER SYSTEMS ACTION  (Continued)
: e. With two or more of the above required diesel generators inoperable, demonstrate the OPERABILITY of two independent A.C. circuits by performing Surveillance Requirement 4.8.1.1.l.a within one hour and at least once per 8 hours thereafter; restore at least two of.the inoperable diesel generators to OPERABLE status within 2 hours or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours. Restore three diesel generators to OPERABLE status within 72 hours from time of initial loss or be in least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
: f. With one of the above required fuel transfer pumps inoperable, either restore it to OPERABLE status within 72 hours or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
: g. With one of the above required fuel storage tanks inoperable, either restore it to OPERABLE status within 72 hours or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
: h. LCO 3.0.4.b is  not applicable to DGs.
SALEM - UNIT 2                       3/4 8-2a                Amendment No. 258

THIS PAGE INTENTIONALLY LEFT BLANK S
SALEM - UNIT 2               3/4 8-2b             Amendment No. 234

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS 4.8.1.1.1 Two physically independent A.C. circuits between the offsite transmission network and the onsite Class 1 E distribution system (vital bus system) shall be:
: a. Determined OPERABLE in accordance with the Surveillance Frequency Control Program by verifying correct breaker alignments, power availability, and
: b. Demonstrated OPERABLE in accordance with the Surveillance Frequency Control Program during shutdown by transferring (manually and automatically) vital bus supply from one 13/4 kv transformer to the other 13/4 kv transformer.
4.8.1.1.2 Each diesel generator shall be demonstrated OPERABLE:
: a. In accordance with the Surveillance Frequency Control Program by:
: 1.      Verifying the fuel level in its day tank.
: 2.      Verifying the diesel generator starts from standby conditions* and achieves a 3910 volts and > 58.8 Hz in < 13 seconds, and subsequently achieves steady state voltage of > 3910 and < 4400 volts and frequency of 60 +/- 1.2 Hz.
Subsequently, verifying the generator is synchronized with voltage maintained > 3910 and < 4580 volts, gradually loaded to 2340-2600 kw**,
and operates at a load of 2340-2600 kw for greater than or equal to 60 minutes.
: 3.      Verifying the diesel generator is aligned to provide standby power to the associated vital bus.
: b. In accordance with the Surveillance Frequency Control Program and after each operation of the diesel where the period of operation was greater than or equal to 1 hour by checking for and removing accumulated water from the day tanks.
: c. In accordance with the Surveillance Frequency Control Program by verifying the diesel generator starts from standby conditions* and achieves > 3910 volts and
               > 58.8 Hz in < 13 seconds, and subsequently achieves steady state voltage of
               > 3910 and < 4400 volts and frequency of 60 +/- 1.2 Hz.
The generator shall be synchronized to its emergency bus with voltage maintained a 3910 and < 4580 volts, loaded to 2340-2600** kw in less than or equal to 60 seconds, and operate at a load of 2340-2600 kw for at least 60 minutes.
This test, if it is performed so it coincides with the testing required by Surveillance Requirement 4.8.1.1.2.a.2, may also serve to concurrently meet those requirements.
SALEM - UNIT 2                                  3/4 8-3                          Amendment No. 282

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued')
: d. In accordance with the Surveillance Frequency Control Program during shutdown by:
: 1. DELETED
: 2. Verifying that, on rejection of a load greater than or equal to 820 kw, the voltage and frequency are restored to > 3910 and 5 4400 volts and 60 +/- 1.2 Hz within 4 seconds, and subsequently achieves a steady state frequency of > 58.8 and -<60.5 Hz.
: 3. Simulating a loss of offsite power by itself, and:
a)       Verifying de-energization of the vital bus and load shedding from the vital bus.
b)      Verifying the diesel starts on the auto-start signal*, energizes the vital bus with permanently connected loads within 13 seconds, energizes the auto-connected shutdown loads through the load sequencer and operates for greater than or equal to 5 minutes while its generator is loaded with the shutdown loads. After energization of these loads, the steady state voltage and frequency of the vital bus shall be maintained at > 3910 and
                             -<4400 volts and > 58.8 and
* 60.5 Hz during this test.
: 4. Verifying that on an ESF actuation test signal without loss of offsite power the diesel generator starts on the auto-start signal and operates on standby for greater than or equal to 5 minutes*. The diesel generator shall achieve > 3910 volts and > 58.8 Hz in <- 13 seconds, and subsequently achieves steady state voltage of a 3910 and -<4400 volts and frequency of > 58.8 and - 60.5 Hz.
: 5.      Deleted
: 6. Simulating a loss of offsite power in conjunction with an ESF actuation test signal, and a)      Verifying de-energization of the vital bus and load shedding from the vital bus.
b)      Verifying the diesel starts on the auto-start signal*, energizes the vital bus with permanently connected loads within 13 seconds, energizes the auto-connected emergency (accident) loads through the load sequencer and operates for greater than or equal to 5 minutes while its generator is loaded with the emergency loads.
After energization of these loads, the steady state voltage and frequency of the vital bus shall be maintained at > 3910 and
                             -<4400 volts and > 58.8 and < 60.5 Hz during this test.
SALEM - UNIT 2                              3/4 8-4                          Amendment No. 282

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)
C)       Verifying that all nonessential automatic diesel generator trips (i.e., other than engine overspeed, lube oil pressure low, 4 KV Bus differential and generator differential) are automatically bypassed
                               .upon loss of voltage on the vital bus concurrent with a safety injection actuation signal.
: 7.       Deleted
: 8.       Verifying that the auto-connected loads to each diesel generator do not exceed the two hour rating of 2860 kw.
: 9.       Verifying that with the diesel generator operating in a test mode (connected to its bus), a simulated safety injection signal overrides the test mode by (1) returning the diesel generator to standby operation and (2) automatically energizing the emergency loads with offsite power.
: e. In accordance with the Surveillance Frequency Control Program or after any modifications which could affect diesel generator interdependence by starting all diesel generators simultaneously*, during shutdown, and verifying that all diesel generators accelerate to at least 58.8 Hz in less than or equal to 13 seconds.
: f. In accordance with the Surveillance Frequency Control Program, the following test shall be performed within 5 minutes of diesel shutdown after the diesel has operated for at least two hours at 2340-2600 kw**:
Verifying the diesel generator starts and achieves _ 3910 volts and > 58.8 Hz in
              < 13 seconds, and subsequently achieves steady state voltage of a 3910 and
              < 4400 volts and frequency of 60 +/- 1.2 Hz.
: g. In accordance with the Surveillance Frequency Control Program verifying the diesel generator operates for at least 24 hours*. During the first 2 hours of this test, the diesel generators shall be loaded to 2760-2860 Kw**. During the remaining 22 hours of this test, the diesel generator shall be loaded to 2500-2600 Kw**. The steady state voltage and frequency shall be maintained at ? 3910 and - 4580 volts and 60 +/- 1.2 Hz during this test.
4.8.1.1.3 The diesel fuel oil storage and transfer system shall be demonstrated OPERABLE:
: a. In accordance with the Surveillance Frequency Control Program by:
: 1.      Verifying the level in each of the above required fuel storage tanks.
: 2.       Verifying that both fuel transfer pumps can be started and transfer fuel from the fuel storage tanks to the day tanks.
SALEM - UNIT 2                                   3/4 8-5                         Amendment No. 282

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)
: b.      In accordance with the Surveillance Frequency Control Program by verifying that a sample of diesel fuel from each of the above required fuel storage tanks is within the acceptable limits specified in Table 1 of ASTM D975-77 when checked for viscosity, water and sediment.
4.8.1.1.4 Reports - NOT USED
        .Surveillance testing may be conducted in accordance with the manufacturer's recommendations regarding engine prelube, warm-up and loading (unless loading times are specified in the individual Surveillance Requirements).
**      This band is meant as guidance to preclude routine exceedances of the diesel generator manufacturer's design ratings. Loads in excess of this band for special testing or momentary variations due to changing bus loads shall not invalidate the test.
SALEM - UNIT 2                                  3/4 8-6                      Amendment No. 282

ELECTRICAL POWER SYSTEMS SU$RVEILLANCE REQUIREMENTS  (Continued)
TABLE 4.8-1 DIESEL GENERATOR TEST SCHEDULE NOT USED SALIM - UNIT 2                        3/4 8-7     SAL~        No~. 185
                                                    - UIT 3/49-7Amendment

ELECTRICAL             POWER       SYSTEMS SHUTDOWN LIMITING CONDITION FOR OPERATION 3.8.1.2 As a minimum,                          the following A.C.                    electrical power sources shall be OPERABLE:
: a.        One circuit between the offsite transmission network and the onsite Class 1E distribution system (vital bus system), and
: b.        Two separate and independent diesel generators with:
: 1.        Separate day tanks containing a minimum volume of 130 gallons of fuel, and
: 2.        A common fuel storage system containing a minimum volume of 23,000 gallons of fuel, and
: 3.        A fuel transfer pump.
APPLICABILITY:                  MODES 5 and 6.
During movement of irradiated fuel assemblies.
ACTION:
: a. With one of the above minimum required A.C. electrical power sources not OPERABLE, immediately declare the affected required features inoperable, or suspend all operations involving CORE ALTERATIONS, movement of irradiated fuel, and positive reactivity changes until the minimum required A.C. electrical power sources are restored to OPERABLE status.
: b. With two of the required diesel generators not OPERABLE, suspend all operations involving CORE ALTERATIONS, movement of irradiated fuel, and all operations involving positive reactivity additions, and immediately initiate action to restore one required DG to OPERABLE status.
SURVEILLANCE REQUIREMENTS
---------------------------------------NOTE ----------------------------------
The following surveillances are not required to be performed to maintain operability during Modes 5 and 6.                                     These surveillances are: 4.8.1.1.1.b, 4.8.1.1.2.d.2, 4.8.1.1.2.d.3, 4.8.1.1.2.d.4,                                              4.8.1.1.2.d.6,                  4.8.1.1.2.d.9, 4.8.1.1,2.e, 4.8.1.1.2.f, and 4.8.1.1.2.g.
4.8.1.2 The above required A.C. electrical power sources shall be demonstrated OPERABLE by the performance of each of the Surveillance Requirements of 4.8.1.1.1, 4.8.1.1.2, 4.8.1.1.3 (except for requirement 4,8.1.1.3.a.2) and 4.8.1.1.4.
SALEM -        &#xfd;ZIIT 2                                                 3/4 8-7a                                            Amendment No. 246

ELECTRICAL POWER SYSTEMS 3/4.8.2 ONSITE POWER DISTRIBUTION SYSTEMS A.C. DISTRIBUTION - OPERATING LIMITING CONDITION FOR OPERATION 3.8.2.1 The following A.C. electrical busses shall be OPERABLE and energized from sources of power other than the diesel generators:
4 kvolt     Vital Bus # 2A 4 kvolt     Vital Bus # 2B 4 kvolt     Vital Bus # 2C 460 volt    Vital Bus # 2A and associated     control centers 460 volt    Vital Bus # 2B and associated     control centers 460 volt    Vital Bus # 2C and associated     control centers 230 volt    Vital Bus # 2A and associated     control centers 230 volt    Vital Bus # 2B and associated     control centers 230 volt    Vital Bus # 2C and associated     control centers 115 volt    Vital Instrument Bus # 2A and     Inverter
* 115 volt    Vital Instrument Bus # 2B and     Inverter
* 115 volt    Vital Instrument Bus #2C and      Inverter
* 115 volt    Vital Instrument Bus # 2D and     Inverter
* APPLICABILITY: MODES 1, 2, 3 and 4.
ACTION:
: a.      With less than the above complement of A.C. busses OPERABLE or energized, restore the inoperable busses to OPERABLE and energized status within 8 hours or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
: b.      With one inverter inoperable, energize the associated A.C. Vital Bus within 8 hours; restore the inoperable 2A, 2B, or 2C inverter to OPERABLE and energized status within 24 hours or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours; restore the inoperable 2D inverter to OPERABLE and energized status within 72 hours or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
SURVEILLANCE REQUIREMENTS 4.8.2.1 The specified A.C. busses and inverters shall be determined OPERABLE and energized from A.C. sources other than the diesel generators in accordance with the Surveillance Frequency Control Program by verifying correct breaker alignment and indicated voltage on the busses.
An inverter may be disconnected from its D.C. source for up to 24 hours for the purpose of performing an equalizing charge on its associated battery bank provided (1) its vital bus is OPERABLE and energized, and (2) the vital busses associated with the other battery banks are OPERABLE and energized.
SALEM - UNIT 2                                   3/4 8-8                          Amendment No. 282

ELECTRICAL POWER SYSTEMS A.C. DISTRIBUTION - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.8.2.2 As a minimum, two A.C. electrical bus trains shall be OPERABLE and energized from sources of power other than a diesel generator but aligned to an OPERABLE diesel generator with each train consisting of:
I -     4 kvolt Vital Bus 1-      460 volt Vital Bus and associated control centers I -     230 volt Vital Bus and associated control centers I -     115 volt Instrument Bus energized from its respective inverter connected to its respective D.C. bus train.
APPLICABILITY: MODES 5 and 6.
During movement of irradiated fuel assemblies.
ACTION:
With less than the above complement of AC. busses and inverters OPERABLE and energized, immediately declare the affected required features inoperable, or suspend all operations involving CORE ALTERATIONS, positive reactivity changes, and movement of irradiated fuel assemblies until the minimum required A.C. electrical power sources are restored to OPERABLE status.
SURVEILLANCE REQUIREMENTS 4.8.2.2 The specified A.C. busses and inverters shall be determined OPERABLE and energized from A.C. sources other than the diesel generators in accordance with the Surveillance Frequency Control Program by verifying correct breaker alignment and indicated voltage on the busses.
SALEM - UNIT 2                                3/4 8-9                        Amendment No. 282

ELECTRICAL POWER SYSTEMS 125-VOLT D.C. DISTRIBUTION - OPERATING LIMITING CONDITION FOR OPERATION 3.8.2.3 The following D.C. bus trains shall be OPERABLE and energized:
TRAIN 2A          consisting of 125-volt D.C. bus No. 2A, 125-volt D.C. battery No. 2A and battery charger 2A1.
TRAIN 2B          consisting of 125-volt D.C. bus No. 2B, 125-volt D.C. battery No. 2B and battery charger 2B1.
TRAIN 2C          consisting of 125-volt D.C. bus No. 2C, 125-volt D.C. battery No. 2C* and battery charger 2C1.
APPLICABILITY:       MODES 1, 2, 3 and 4.
ACTION:
: a.       With one 125-volt D.C. bus inoperable or not energized, restore the inoperable bus to OPERABLE and energized status within 2 hours or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
: b.       With one 125-volt D.C. battery charger inoperable, restore the inoperable charger to OPERABLE status within 2 hours or connect the backup charger for no more than 7 days or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
: c.      With one or more 125-volt D.C. batteries with one or more battery cell parameters not within the Category A or B limits of Table 4.8.2.3-1:
: 1.       Verify within 1 hour, that the electrolyte level and float voltage for the pilot cell meets Table 4.8.2.3-1 Category C limits, and
: 2.       Verify within 24 hours, that the battery cell parameters of all connected cells meet Table 4.8.2.3-1 Category C limits, and
: 3.       Restore battery cell parameters to Category A and B limits of Table 4.5.2.3-1 within 31 days, and
: 4.       If any of the above listed requirements cannot be met, comply with the requirements of action f.
: d.       With one or more 125-volt D.C. batteries with one or more battery cell parameters not within Table 4.8.2.3-1 Category C values, comply with the requirements of action f.
: e.      With average electrolyte temperature of representative cells lessthan 65'F, comply with the requirements of action f.
: f.       Restore the battery to OPERABLE status within 2 hours or be in at least HOT STANDBY within the next 6 hours and COLD SHUTDOWN within the following 30 hours.
During the one-time on-line replacement of station bzttery 2C, this LCO can be satisfied by a temporary battery as described in PSEG LAR submittal dated March 29, 2010.
SALEM - UNIT 2                                     3/4 8-10                              Amendment No. 280

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS 4.8.2.3.1 Each D.C. bus train shall be determined OPERABLE and energized in accordance with the Surveillance Frequency Control Program by verifying correct breaker alignment and voltage on the bus.
4.8.2.3.2 Each required 125-volt battery and charger shall be demonstrated OPERABLE:
: a. In accordance with the Surveillance Frequency Control Program by verifying that:
: 1.      The parameters in Table 4.8.2.3-1 meet Category A limits.
: 2.      The overall battery voltage is greater than or equal to 125 volts on float charge.
: b. In accordance with the Surveillance Frequency Control Program and once within 24 hours after a battery discharge < 110 V and once within 24 hours after a battery overcharge > 150 V by verifying that the parameters in Table 4.8.2.3-1 meet the Category B limits.
: c. In accordance with the Surveillance Frequency Control Program by verifying that:
: 1. There is no visible corrosion at terminals or connectors or the connection resistance is:
                                 -<150 micro ohms for inter-cell connections,
                                 -<350 micro ohms for inter-rack connections, 5 350 micro ohms for inter-tier connections,
                                <- 70 micro ohms for field cable terminal connections, and
                                 -<2500 micro ohms for the total battery connection resistance which includes all inter-cell connections (including bus bars), all inter-rack connections (including cable resistance), all inter-tier connections (including cable resistance), and all field terminal connections at the battery.
: 2.      The average electrolyte temperature of the representative cells is above 65 0 F.
: d.      In accordance with the Surveillance Frequency Control Program by verifying that:
: 1. The cells, cell plates and battery racks show no visual indication of physical damage or abnormal deterioration.
: 2.       Remove visible terminal corrosion and verify cell-to-cell and terminal connections are coated with anti-corrosion material.
SALEM - UNIT 2                                 3/4 8-11                         Amendment No. 282

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)
: 3.      The connection resistance is:
                              <150 micro ohms for inter-cell connections,
                              <350 micro ohms for inter-rack connections,
                              <350 micro ohms for inter-tier connections, 570 micro ohms for field cable terminal connections,and
                              <2500 micro ohms for the total battery connection resistance which includes all inter-cell connections (including bus bars), all inter-rack connections (including cable resistance) all inter-tier connections (including cable resistance) and all field terminal connections at the battery.
: e.      In accordance with the Surveillance Frequency Control Program by verifying that the battery charger will supply at least 170 amperes at 125 volts for at least 4 hours.
: f.      In accordance with the Surveillance Frequency Control Program, during shutdown*, by verifying that the battery capacity is adequate to supply and maintain in OPERABLE status all of the actual or simulated emergency loads for the design duty cycle when the battery is subjected to a battery service test.
: g.      In accordance with the Surveillance Frequency Control Program, during shutdown*, by verifying that the battery capacity is at least 80% of the manufacturer's rating when subjected to a performance discharge test.
Satisfactory completion of this performance discharge test shall also satisfy the requirements of Specification 4.8.2.3.2.f if the performance discharge test is conducted during a shutdown* where that test and the battery service test would both be required.
: h.      At least once per 12 months, during shutdown, if the battery shows signs of degradation OR has reached 85% of the service life with a capacity less than 100% of manufacturers rating, by verifying that the battery capacity is at least 80% of the manufacturer's rating when subjected to a performance discharge test. Degradation is indicated when the battery capacity drops more than 10% of rated capacity from its capacity on the previous performance test, or is below 90% of the manufacturer's rating.
At least once per 24 months, during shutdown, if the battery has reached 85% of the service life with capacity greater than or equal to 100% of manufacturers rating, by verifying that the battery capacity is at least 80% of the manufacturer's rating when subjected to a performance discharge test.
This battery surveillance may be performed, as required, associated with a one-time replacement of station battery 2C when the unit is not shutdown. This testing shall be done when the battery is disconnected from the 2C DC bus. This testing must be completed by February 1, 2011.
SALEM - UNIT 2                              3/4 8-11 a                        Amendment No. 282

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS      (Continued)
TABLE 4.8.2.3-1 BATTERY CELL PARAMETERS REQUIREMENTS CATEGORY A:            CATEGORY B:          CATEGORY C:
PARAMETER             LIMITS FOR EACH        LIMITS FOR EACH      ALLOWABLE VALUE DESIGNATED PILOT       CONNECTED CELL       FOR EACH CELL                                        CONNECTED CELL Electrolyte Level      >Minimum level        >Minimum level       Above top of indication mark,       indication mark,     plates, and not and
* 1/4 inch         and g 1/4 inch       overflowing above maximum          above maximum level indication       level indication mark (a)               mark (a)
Float Voltage                &#x17d;2.13 V               &#x17d;2.13 V              k2.07 V Specific Gravity              >I.195               2:1.190        Not more than (b) (c)                                                          0.020 below AND          average of all connected cells Average of all connected cells            AND
                                                     >1.200 Average of all connected cells k1.190 (a)       It is acceptable for the electrolyte level to temporarily increase above the specified maximum level during equalizing charge provided it is not overflowing.
(b)       Corrected for electrolyte temperature and level.      Level correction is not required, however, when battery charging is < 3 amps when on float charge.
(c)      Or battery charging current is < 3 amps when on float charge.        This is acceptable only during a maximum of 7 days following a battery recharge.
SALEM - UNIT 2                           3/4 8-11b                     Amendment No. 158

ELECTRICAL POWER SYSTEMS 125-VOLT D.C. DISTRIBUTION - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.8.2.4 As a minimum, the following D.C. electrical equipment and bus shall be energized and OPERABLE:
2-     125-volt D.C. busses, and 2-     125-volt batteries, each with at least one full capacity charger, associated with each of the above D.C. busses.
APPLICABILITY: MODES 5 and 6.
During movement of irradiated fuel assemblies.
ACTION:
With less than the above complement of D.C. equipment and busses OPERABLE, immediately declare the affected required features inoperable, or suspend all operations involving CORE ALTERATIONS, positive reactivity changes, and movement of irradiated fuel assemblies until the minimum required 125 Volt D.C. electrical power sources are restored to OPERABLE status.
SURVEILLANCE REQUIREMENTS 4.8.2.4.1 The above required 125-volt D.C. busses shall be determined OPERABLE and energized in accordance with the Surveillance Frequency Control Program by verifying correct breaker alignment and indicated power availability.
4.8.2.4.2 The above required 125-volt batteries and chargers shall be demonstrated OPERABLE per Surveillance Requirement 4.8.2.3.2.
SALEM - UNIT 2                               3/4 8-12                         Amendment No. 282

ELECTRICAL POWER SYSTEMS 28-VOLT D.C.      DISTRIBUTION - OPERATING LIMITING CONDITION FOR OPERATION 3.8.2.5      The following D.C. bus trains shall be energized and OPERABLE:
TRAIN 2A consisting of 28-volt D.C. bus No. 2A,       28-volt D.C.
battery No. 2A and battery charger 2A1.
TRAIN 2B consisting of 28-volt D.C. bus No. 2B,       28-volt D.C.
battery No. 2B, and battery charger 2B1.
APPLICABILITY: MODES 1, 2,      3 and 4.
ACTION:
: a. With one 28-volt D.C. bus inoperable or not energized, restore the inoperable bus to OPERABLE and energized status within 2 hours or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
: b. With one required 28-volt D.C. battery charger inoperable, restore the inoperable charger to OPERABLE status within 2 hours or connect the backup charger for no more than 7 days or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
: c. With one or more 28-volt D.C. batteries with one or more battery cell parameters not within the Category A or B limits of Table 4.8.2.5-1:
: 1. Verify within 1 hour, that the electrolyte level and float voltage for the pilot cell meets Table 4.8.2.5-1 Category C limits, and
: 2. Verify within 24 hours, that the battery cell parameters of all connected cells meet Table 4.8.2.5-1 Category C limits, and
: 3. Restore battery cell parameters to Category A and B limits of Table 4.8.2.5-1 within 31 days, and
: 4. If any of the above listed requirements cannot be met, comply with the requirements of action f.
: d.       With one or more 28-volt D.C. batteries with one or more battery cell parameters not within Table 4.8.2.5-1 Category C values, comply with the requirements of action f.
: e.       With average electrolyte temperature of representative cells less than'650 F, comply with the requirements of action f.
: f.      Restore the battery to OPERABLE status within 2 hours or be in at least HOT STANDBY within the next 6 hours and COLD SHUTDOWN within the following 30 hours.
SALEM - UNIT 2                           3/4 8-13                 Amendment No. 229

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS 4.8.2.5.1 Each D.C. bus train shall be determined OPERABLE and energized in accordance with the Surveillance Frequency Control Program by verifying correct breaker alignment and power availability.
4.8.2.5.2 Each 28-volt battery and above required charger shall be demonstrated OPERABLE:
: a.      In accordance with the Surveillance Frequency Control Program by verifying that:
: 1.      The parameters in Table 4.8.2.5-1 meet Category A limits.
: 2.      The overall battery voltage is greater than or equal to 27 volts on float charge.
: b.      In accordance with the Surveillance Frequency Control Program and once within 24 hours after a battery discharge < 25.7 V and once within 24 hours after a battery overcharge > 35 V by verifying that the parameters in Table 4.8.2.5-1 meet the Category B limits.
: c.      In accordance with the Surveillance Frequency Control Program by verifying that:
: 1.      There is no visible corrosion at terminals or connectors or the connection resistance is:
:5 50 micro ohms for inter-cell connections, 5 200 micro ohms for inter-tier connections,
                                < 70 micro ohms for field cable terminal connections, and
                                < 500 micro ohms for the total battery connection resistance which includes all inter-cell connections (including bus bars), all inter-tier connections (including cable resistance) and all field terminal connections at the battery.
: 2.       The average electrolyte temperature of the representative cells is a 65&deg;F.
SALEM - UNIT 2                                  3/4 8-14                        Amendment No. 282

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)
: d. In accordance with the Surveillance Frequency Control Program by verifying that:
: 1.      The cells, cell plates and battery racks show no visual indication of physical damage or abnormal deterioration.
: 2.       Remove visible terminal corrosion and verify cell-to-cell and terminal connections are coated with anti-corrosion material.
: 3.      The connection resistance is:
                             - 50 micro ohms for inter-cell connections,
:- 200 micro ohms for inter-tier connections, s 70 micro ohms for field cable terminal connections, and
                              -5500 micro ohms for the total battery connection resistance which includes all inter-cell connections (including bus bars), all inter-tier connections (including cable resistance) and all field terminal connections at the battery.
: e. In accordance with the Surveillance Frequency Control Program by verifying that the battery charger will supply L>150 amperes at ->28 volts for ? 4 hours.
: f. In accordance with the Surveillance Frequency Control Program, during shutdown, by verifying that the battery capacity is adequate to supply and maintain in OPERABLE status all of the actual or simulated emergency loads for the design duty cycle when the battery is subjected to a battery service test.
: g. In accordance with the Surveillance Frequency Control Program, during shutdown, by verifying that the battery capacity is at least 80% of the manufacturer's rating when subjected to a performance discharge test.
Satisfactory completion of this performance discharge test shall also satisfy the requirements of Specification 4.8.2.5.2.f ifthe performance discharge test is conducted during a shutdown where that test and the battery service test would both be required.
: h. At least once per 12 months, during shutdown, if the battery shows signs of degradation OR has reached 85% of the service life with a capacity less than 100% of manufacturers rating, by verifying that the battery capacity is at least 80% of the manufacturer's rating when subjected to a performance discharge test. Degradation is indicated when the battery capacity drops more than 10% of rated capacity from its capacity on the previous performance test, or is below 90% of the manufacturer's rating.
At least once per 24 months, during shutdown, if the battery has reached 85% of the service life with capacity greater than or equal to 100% of manufacturers rating, by verifying that the battery capacity is at least 80% of the manufacturer's rating when subjected to a performance discharge test.
SALEM - UNIT 2                              3/4 8-14a                        Amendment No. 282

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS    (Continued)
TABLE 4.8.2.5-1 BATTERY CELL PARAMETER REQUIREMENTS CATEGORY A:              CATEGORY B:          CATEGORY C:
PARAMETER        LIMITS FOR EACH          LIMITS FOR EACH      ALLOWABLE VALUE DESIGNATED PILOT CELL    CONNECTED CELL       FOR EACH CONNECTED CELL Electrolyte      >Minimum level           >Minimum level       Above top of Level            indication mark and      indication mark-     plates and not
* 1/4 inch above         and
* 1/4 inch       overflowing maximum level            above maximum indication mark~a)       level indication mark(a)
Float Voltage            &#x17d;2.13 V                &#x17d;2.13 V              >2.07 V Specific                 >1.195                   :1.190       Not more than Gravitymb' (c)                                                 0.020 below the AND        average of all connected cells Average of all Connected cells              AND
:1.200        Average of all connected cells
                                                                       &#x17d;l. 190 (a)    It is acceptable for the electrolyte level to temporarily increase above the specified maximum level during equalizing charge provided it is not overflowing.
(b)    Corrected for electrolyte temperature and level.      Level correction is   not required, however, when battery charging is < 2 amps when on float charge.
(c)    Or battery charging current is < 2 amps when on float charge.       This is acceptable only during a maximum of 7 days following a battery recharge.
SALEM - UNIT 2                        3/4 8-14b             Amendment No. 229

ELECTRICAL POWER SYSTEMS 28-VOLT D.C. DISTRIBUTION - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.8.2.6 As a minimum, the following D.C. electrical equipment and bus shall be energized and OPERABLE:
1-     28-volt D.C. bus, and 1-     28-volt battery and at least one full capacity charger associated with the above D.C. bus.
APPLICABILITY: MODES 5 and 6.
During movement of irradiated fuel assemblies.
ACTION:
With less than the above complement of D.C. equipment and busses OPERABLE, immediately declare the affected required features inoperable, or suspend all operations involving CORE ALTERATIONS, positive reactivity changes, and movement or irradiated fuel assemblies until the minimum required 28 Volt D.C. electrical power sources are restored to OPERABLE status.
SURVEILLANCE REQUIREMENTS 4.8.2.6.1 The above required 28-volt D.C. bus shall be determined OPERABLE and energized in accordance with the Surveillance Frequency Control Program by verifying correct breaker alignment and voltage on the bus.
4.8.2.6.2 The above required 28-volt batteries and charger shall be demonstrated OPERABLE per Surveillance Requirement 4.8.2.5.2.
SALEM - UNIT 2                                3/4 8-15                        Amendment No. 282

ELECTRICAL POWER SYSTEMS 3/4.8.3 ELECTRICAL EQUIPMENT PROTECTIVE DEVICES CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES LIMITING CONDITION FOR OPERATION 3.8.3.1 All containment penetration conductor overcurrent protective devices required to provide thermal protection of penetrations shall be OPERABLE.
APPLICABILITY: MODES 1, 2, 3 and 4.
ACTION:
With one or more of the containment penetration conductor overcurrent protective device(s) inoperable:
: a. Restore the protective device(s) to OPERABLE status or de-energize the circuit(s) by tripping either the primary or backup protective device, or racking out or removing the primary or backup device within 72 hours, declare the affected system or component inoperable, and verify the primary or backup protective device to be tripped, or the primary or backup device racked out or removed at least once per 7 days thereafter; or
: b. Be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.
SURVEILLANCE REQUIREMENTS 4.8.3.1 All required containment penetration conductor overcurrent protective devices shall be demonstrated OPERABLE:
: a. In accordance with the Surveillance Frequency Control Program:
: 1.       For 4.16 KV reactor coolant pump circuits, by performance of:
(a)      A CHANNEL CALIBRATION of the associated protective relays, and (b)      An integrated system functional test which includes simulated automatic actuation of the system and verifying that each relay and associated circuit breakers and control circuits function as designed.
SALEM - UNIT 2                                  3/4 8-16                       Amendment No. 282

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)
: 2. By verifying the OPERABILITY of the required molded case and lower voltage circuit breakers, by selecting and functionally testing a representative sample of at least 10% of all the circuit breakers of that type. Circuit breakers selected for functional testing shall be selected on a rotating basis. The functional test shall consist of injecting a current input at the specified setpoint to each selected circuit breaker and verifying that each circuit breaker functions as designed. Circuit breakers found inoperable during functional testing shall be restored to OPERABLE status prior to resuming operation. For each circuit breaker found inoperable during the functional tests, an additional representative sample of at least 10% of all the circuit breakers of the inoperable type shall also be functionally tested until no more failures are found or all circuit breakers of that type have been functionally tested.
: b. In accordance with the Surveillance Frequency Control Program by subjecting each circuit breaker to an inspection and preventive maintenance in accordance with procedures prepared in conjunction with its manufacturer's recommendations.
SALEM - UNIT 2                             3/4 8-17                         Amendment No. 282

M DELETED SALEN - UNIT 2 3/4 8-18     Amendment No. 82

3/4.9 REFUELING OPERATIONS BORON CONCENTRATION LIMITING CONDITION FOR OPERATION 3.9.1 The boron concentration of the Reactor Coolant System, the fuel storage pool, the refueling canal, and the refueling cavity shall be maintained within the limit specified in the CORE OPERATING LIMITS REPORT (COLR).
APPLICABILITY: MODE 6 (Only applicable to the refueling canal, the fuel storage pool and refueling cavity when connected to the Reactor Coolant System)
ACTION:
With the requirements of the above specification not satisfied, immediately
: a.      Suspend CORE ALTERATIONS and
: b.      Suspend positive reactivity additions and
: c.      Initiate action to restore boron concentration to within limit specified in the COLR.
: d.      The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REQUIREMENTS 4.9.1 Verify the boron concentration is within the limit of the COLR in accordance with the Surveillance Frequency Control Program.
SALEM - UNIT 2                                  3/4 9-1                          Amendment No. 282

REFUELING OPERATIONS 3/4.9.2 INSTRUMENTATION LIMITING CONDITION FOR.OPERATION 3.9.2 As a minimum, two source range neutron flux monitors shall be operating, each with continuous visual indication in the control room and one with audible indication in the containment and control room.
APPLICABILITY: MODE 6.
ACTION:
: a. With one of the above required monitors inoperable, immediately suspend all operations involving CORE ALTERATIONS or positive reactivity changes.
: b. With both of the required monitors inoperable, determine the boron concentration of the reactor coolant system at least once per 12 hours.
: c. The provisions of Specification 3.0.3 are not applicable.
U1J.RVILLANCE REQUIREMENTS 4.9.2 Each source range neutron flux monitor shall be demonstrated OPERABLE by performance of:
: a. A CHANNEL CHECK in accordance with the Surveillance Frequency Control Program, and
: b. A CHANNEL FLINCTIONAL TEST in accordance with the Surveillance Frequency Control Program.
SALEM - UNIT 2                                 3/4 9-2                       Amendment No. 282

REFUELING OPERATIONS DECAY TIME LIMITING CONDITION FOR OPERATION 3.9.3     The reactor shall be subcritical   for at least:
: a. 80 hours
: b. 168 hours APPLICABILITY:    Specification 3.9.3.a - From October    1 5 th through May 1 5 th, during movement of irradiated fuel in     the reactor pressure vessel.
th                          th Specification  3.9.3.b   -  From  May   16t     through   October     14 during movement   of  irradiated   fuel     in   the  reactor   pressure vessel.
ACTION:
With the reactor subcritical for less than the required time, suspend all operations involving movement of irradiated fuel in                the reactor pressure vessel. The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REQUIREMENTS 4.9.3   The reactor shall be determined to have been subcritical as required by verification of the date and time of subcriticality prior to movement of irradiated fuel in the reactor pressure vessel.
SALEM  -UNIT   2                   3/4 9-3                         Amendment No. 273

REFUELING OPERATIONS CONTAINMENT BUILDING PENETRATIONS LIMITING CONDITION FOR OPERATION 3.9.4 The containment building penetrations shall be in the following status:
: a.      The equipment hatch inside door is capable of being closed and held in place by a minimum of four bolts, or an equivalent closure device installed and capable of being closed,
: b.      A minimum of one door in each airlock is capable of being closed
: c.      Each penetration providing direct access from the containment atmosphere to the outside atmosphere shall be either:
: 1.      closed by a manual or automatic isolation valve, blind flange, or equivalent, or
: 2.      capable of being closed by the Containment Purge and Pressure-Vacuum Relief Isolation System.
Note: Penetration flow path(s) providing direct access from the containment atmosphere to the outside atmosphere may be unisolated under administrative controls.
APPLICABILITY: During movement of irradiated fuel within the containment.
ACTION:
With the requirements of the above specification not satisfied, immediately suspend all operations involving movement of irradiated fuel in the containment building. The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REQUIREMENTS 4.9.4.1 Each of the above required containment building penetrations shall be determined to be either in its required condition or capable of being closed by a manual or automatic containment isolation valve in accordance with the Surveillance Frequency Control Program.
4.9.4.2 Once per refueling prior to the start of movement of irradiated fuel assemblies within the containment building, verify the capability to close, within 1 hour, the equipment hatch inside door or an equivalent closure device. Applicable only when the equipment hatch is open during movement of irradiated fuel in the containment building.
4.9.4.3 Verify, in accordance with the Surveillance Frequency Control Program, each required containment purge isolation valve actuates to the isolation position on a manual actuation signal.
SALEM - UNIT 2                                  3/4 9-4                        Amendment No. 282

REFUELING OPERATIONS THIS PAGE INTENTIONALLY BANK SALEM - UNIT 2                   3/4 9-5         Amendment No. 277

REFUELING OPERATIONS THIS PAGE INTENTIONALLY BANK SALEM - UNIT 2                   3/4 9-6          Amendment No. 277

REFUELING OPERATIONS THIS PAGE INTENTIONALLY BANK SALEM - UNIT 2               3/4 9-7             Amendment No. 277

REFUELING OPERATIONS 3/4.9.8 RESIDUAL HEAT REMOVAL AND COOLANT CIRCULATION ALL WATER LEVELS LIMITING CONDITION FOR OPERATION 3.9.8.1 At least one residual heat removal loop shall be in operation.
APPLICABILITY: MODE 6.
ACTION:
: a.      With less than one residual heat removal loop in operation, except as provided in
: b. below, suspend all operations involving an increase in the reactor decay heat load or a reduction in boron concentration of the Reactor Coolant System. Close all containment penetrations providing direct access from the containment atmosphere to the outside atmosphere within 4 hours.
: b.      The residual heat removal loop may be removed from operation for up to 1 hour per 8 hour period during the performance of CORE ALTERATIONS in the vicinity of the reactor pressure vessel hot legs.
: c.      The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REQUIREMENTS 4.9.8.1 In accordance with the Surveillance Frequency Control Program one RHR loop shall be verified in operation and circulating coolant at a flow rate of:
: a.      greater than or equal to 1000 gpm, and
: b.      sufficient to maintain the RCS temperature at less than or equal to 140&deg;F.
SALEM - UNIT 2                                 3/4 9-8                        Amendment No. 282

REFUELING OPERATIONS LOW WATER LEVEL LIMITING CONDITION FOR OPERATION 3.9.8.2 Two independent Residual Heat Removal (RHR) loops shall be OPERABLE.*
APPLICABILITY: MODE 6 when water level above the top of the reactor pressure vessel flange is less than 23 feet.
ACTION:
: a. With less than the required RHR loops operable, immediately initiate corrective' action to return the required RHR loops to OPERABLE status as soon as possible.
: b. The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REQUIREMENTS 4.9.8.2 The required Residual Heat Removal loops shall be determined OPERABLE per the Inservice Testing Program.
Syste~ms supporting RHR loop operability may be excepted as follows:
: a.      The normal or emergency power source may be inoperable.
SALEM - UNIT 2                                3/4 9-9                     Amendment No. 279

REFUELING OPERATIONS THIS PAGE INTENTIONALLY BLANK                   I SALEM - UNIT 2                   3/4 9-10         Amendment No. 245

REFUELING OPERATIONS 3/4.9.10 WATER LEVEL - REACTOR VESSEL LIMITING CONDITION FOR OPERATION 3.9.10 At least 23 feet of water shall be maintained over the top of the reactor pressure vessel flange.
APPLICABILITY: During movement of fuel assemblies or control rods within the reactor pressure vessel when either the fuel assemblies being moved or the fuel assemblies seated within the reactor pressure vessel are irradiated.
ACTION:
With the requirements of the above specification not satisfied, suspend all operations involving movement of fuel assemblies or control rods within the pressure vessel. The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REQUIREMENTS 4.9.10 The water level shall be determined to be at least its minimum required depth within 2 hours prior to the start of and in accordance with the Surveillance Frequency Control Program thereafter during movements of fuel assemblies or control rods.
SALEM - UNIT 2                                3/4 9-11                        Amendment No. 282

REFUELING OPERATIONS 3/4.9.11 STORAGE POOL WATER LEVEL LIMITING CONDITION FOR OPERATION 3.9.11 At least 23 feet of water shall be maintained over the top of irradiated fuel assemblies seated in the storage racks.
APPLICABILITY: Whenever irradiated fuel assemblies are in the storage pool.
ACTION:
With the requirements of the specification not satisfied, suspend all movement of fuel assemblies and crane operations with loads in the fuel storage areas and restore water level to within its limit within 4 hours. The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REQUIREMENTS 4.9.11 The water level in the storage pool shall be determined to be at least its minimum required depth in accordance with the Surveillance Frequency Control Program when irradiated fuel assemblies are in the fuel storage pool.
SALEM - UNIT 2                                 3/4 9-12                         Amendment No. 282

REFUELING OPERATIONS 3/4.9.12 FUEL HANDLING AREA VENTILATION SYSTEM LIMITING CONDITION FOR OPERATION 3.9.12 The Fuel Handling Area Ventilation System shall be OPERABLE with:
: a. Two exhaust fans and one supply fan OPERABLE and operating, and
: b. Capable of maintaining slightly negative pressure in the Fuel Handling Building.
APPLICABILITY: During movement of irradiated fuel within the Fuel Handling Building ACTION:
: a. With no Fuel Handling Area Ventilation System OPERABLE, suspend all operations involving movement of fuel within the storage pool until the Fuel Handling Area Ventilation System is restored to OPERABLE status.
: b. The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REQUIREMENTS 4.9.12       The above required ventilation system shall be demonstrated OPERABLE:
: a. In accordance with the Surveillance Frequency Control Program by verifying that the Fuel Handling Building is maintained at a slightly negative pressure with respect to atmospheric pressure.
: b. In accordance with the Surveillance Frequency Control Program by verifying both exhaust fans and one supply fan start and operate for at least 15 minutes, if not operating already.
: c. In accordance with the Surveillance Frequency Control Program by verifying a system flowrate of 19,490 cfm +/- 10% during system operation.
SALEM - UNIT 2                             3/4 9-13                        Amendment No. 282

3/4.10 SPECIAL TEST EXCEPTIONS SHUTDOWN MARGIN LIMITING CONDITION FOR OPERATION 3.10.1 The SHUTDOWN MARGIN requirement of Specification 3.1.1.1 may be suspended for measurement of control rod worth and shutdown margin provided the reactivity equivalent to at least the highest estimated control rod worth is available for trip insertion from OPERABLE control rod(s).
APPLICABILITY: MODE 2.
ACTION:
: a.      With any full length control rod not fully inserted and with less than the above reactivity equivalent available for trip insertion, immediately initiate and continue boration at > 33 gpm of a solution containing > 6,560 ppm boron or its equivalent until the SHUTDOWN MARGIN required by Specification 3.1.1.1 is restored.
: b.      With all full length control rods inserted and the reactor subcritical by less than the above reactivity equivalent, immediately initiate and continue boration at > 33 gpm of a solution containing > 6,560 ppm boron or its equivalent until the SHUTDOWN MARGIN required by Specification 3.1.1.1 is restored.
SURVEILLANCE REQUIREMENTS 4.10.1.1 The position of each full length rod either partially or FULLY WITHDRAWN shall be determined in accordance with the Surveillance Frequency Control Program.
4.10.1.2 Each full length rod not fully inserted shall be demonstrated capable of full insertion when tripped from at least the 50% withdrawn position within 24 hours prior to reducing the SHUTDOWN MARGIN to less than the limits of Specification 3.1.1.1.
SALEM - UNIT 2                                  3/4 10-1                         Amendment No. 282

SPECIAL TEST EXCEPTIONS GROUP HEIGHT, INSERTION AND POWER DISTRIBUTION LIMITS LIMITING CONDITION FOR OPERATION 3.10.2 The group height, insertion and power distribution limits of Specifications 3.1.3.1, 3.1.3.4, 3.1.3.5, 3.2.1, and 3.2.4 may be suspended during the performance of PHYSICS TESTS provided:
: a.      The THERMAL POWER is maintained less than or equal to 85%# of RATED THERMAL POWER, and
: b.      The limits of Specifications 3.2.2 and 3.2.3 are maintained and determined at the frequencies specified in Specification 4.10.2.2 below.
APPLICABILITY: MODE 1.
ACTION:
With any of the limits of Specifications 3.2.2 or 3.2.3 being exceeded while the requirements of Specifications 3.1.3.1, 3.1.3.4, 3.1.3.5, 3.2.1 and 3.2.4 are suspended, either:
: a.      Reduce THERMAL POWER sufficient to satisfy the ACTION requirements of Specifications 3.2.2 and 3.2.3, or
: b.      Be in HOT STANDBY within 6 hours.
SURVEILLANCE REQUIREMENTS 4.10.2.1 The THERMAL POWER shall be determined to be less than or equal to 85% of RATED THERMAL POWER in accordance with the Surveillance Frequency Control Program during PHYSICS TESTS.
4.10.2.2 The below listed surveillance requirements shall be performed in accordance with the Surveillance Frequency Control Program during PHYSICS TESTS:
: a.      Surveillances 4.2.2.2 and 4.2.2.3.
: b.      Surveillances 4.2.3.1 and 4.2.3.2.
#       See page 314 10-3 SALEM - UNIT 2                                 314 10-2                       Amendment No. 282

SPECIAL TEST EXCEPTIONS SURVEILLANCE REQUIREMENTS (Continued)
#A-THERMAL POWER limit of 100% of RATED THERMAL POWER is permissible during the Power Coefficient Test and the Load Swing Test Performed as part of the Initial Startup Test Program, provided the following conditions are met:
: 1. The target axial offset at full Power shall be less negative or equal to -16%.
: 2. The AI value during the Test shall not be more negative than -23%
at 90% power and -25% at 80% power.
: 3. Before initiation of the test, Bank D control group shall be positioned as far out of the core as possible, consistent with minimum differential rod worth requirements, no lower than 190 steps.
: 4. The limits of Specification 3.1.3.5 shall not be violated.
: 5. Each of the above tests (Power Coefficient Test and Load Swing Test) shall be performed in less than or equal to 2 hours and thest tests shall be completed prior to exceeding a core average fuel burnup of 3000 MWD/MTU.
SALEM - UNIT 2                  3/4 10-3

SPECIAL TEST EXCEPTIONS PHYSICS TESTS LIMITING CONDITION FOR OPERATION 3.10.3 The limitations of Specifications 3.1.1.3, 3.1.1.4, 3.1.3.1, 3.1.3.4 and 3.1.3.5 may be suspended during the performance of PHYSICS TESTS provided:
: a. The THERMAL POWER does not exceed 5% of RATED THERMAL POWER,
: b. The reactor trip setpoints on the OPERABLE Intermediate and Power Range Nuclear Channels are set at less than or equal to 25% of RATED THERMAL POWER, and
: c. The Reactor Coolant System lowest operating loop temperature (Tavg) is greater than or equal to 531&deg;F.
APPLICABILITY: MODE 2.
ACTION:
: a. With the THERMAL POWER greater than 5% of RATED THERMAL POWER, immediately open the reactor trip breakers.
: b. With a Reactor Coolant System operating loop temperature (Tavg) less than 531 OF, restore Tavg to within its limit within 15 minutes or be in at least HOT STANDBY within the next 15 minutes.
SURVEILLANCE REQUIREMENTS 4.10.3.1 The THERMAL POWER shall be determined to be less than or equal to 5% of RATED THERMAL POWER in accordance with the Surveillance Frequency Control Program during PHYSICS TESTS.
4.10.3.2 Each Intermediate and Power Range Channel shall be subjected to a CHANNEL FUNCTIONAL TEST prior to initiating PHYSICS TESTS.
4.10.3.3 The Reactor Coolant System temperature (Tavg) shall be determined to be greater than or equal to 531 OF in accordance with the Surveillance Frequency Control Program during PHYSICS TESTS.
SALEM - UNIT 2                                 3/4 10-4                          Amendment No. 282

SPECIAL TEST EXCEPTIONS NO FLOW TESTS LIMITING CONDITION FOR OPERATION 3.10.4 The limitations of Specification 3.4.1.1 may be suspended during the performance of startup and PHYSICS TESTS, provided:
: a.      The THERMAL POWER does not exceed the P-7 Interlock Setpoint, and
: b.      The Reactor Trip Setpoints on the OPERABLE Intermediate and Power Range Channels are set less than or equal to 25% of RATED THERMAL POWER APPLICABILITY: During operation below the P-7 Interlock Setpoint.
ACTION:
With the THERMAL POWER greater than the P-7 Interlock Setpoint, immediately open the reactor trip breakers.
SURVEILLANCE REQUIREMENTS 4.10.4.1 The THERMAL POWER shall be determined to be less than P-7 Interlock Setpoint in accordance with the Surveillance Frequency Control Program during startup and PHYSICS TESTS.
4,10.4.2 Each Intermediate, Power Range Channel and P-7 Interlock shall be subjected to a CHANNEL FUNCTIONAL TEST prior to initiating startup or PHYSICS TESTS.
SALEM - UNIT 2                                3/4 10-5                     Amendment No. 282

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SALEM - UNIT 2       3/4 11-6 Amendment zio. 215

RADIOACTIVE EFFLUENTS LIQUID HOLDUP TANKS*
LIMITING CONDITION FOR OPERATION 3.11.1.4 The quantity of radioactive material contained in each outdoor temporary tank shall be limited to less than or equal to 10 curies, excluding tritium and dissolved or entrained noble gases.
APPLICABILITY: At all times.
ACTION:
: a.       With the quantity of radioactive material in any of the above listed tanks exceeding the above limit, immediately suspend all additions of radioactive material to the tank and within 48 hours reduce the tank contents to within the limit.
: b.      The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REQUIREMENTS 4.11.1.4 The quantity of radioactive material contained in each outdoor temporary tank shall be determined to be within the above limit by analyzing a representative sample of the tank's contents in accordance with the Surveillance Frequency Control Program when radioactive materials are being added to the tank.
Tanks included in this Specification are those outdoor temporary 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.
SALEM - UNIT 2                                  3/4 11-7                        Amendment No. 282

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SALEM - UNIT 2        3/4 11-14 Amendment No. 215

RADIOACTIVE EFFLUENTS EXPLOSIVE GAS MIXTURE LIMITING CONDITION FOR OPERATION 3.11.2.5 The concentration of oxygen in the waste gas holdup system shall be limited to less than or equal to 2% by volume.
APPLICABILITY: At all times.
* ACTION:
: a.      With the concentration of oxygen in the waste gas holdup system greater than 2% by volume but less than or equal 4% by volume, reduce the oxygen concentration to the above limits within 48 hours.
: b.      With the concentration of oxygen in the waste gas holdup system greater than 4% by volume immediately suspend all additions of waste gases to the system and reduce the concentration of oxygen to less than or equal to 2% by volume without delay.
: c.      The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REQUIREMENTS 4.11.2.5 The concentration of oxygen in the waste gas holdup system shall be determined to be within the above limits by continuously** monitoring the waste gases in the waste gas holdup system with the oxygen monitor. If hydrogen is not measured, the concentration of hydrogen shall be assumed to exceed 4% by volume.
Not applicable to portions of the Waste Gas System removed from service for maintenance provided that, the portions removed for maintenance are isolated, and purged of hydrogen to less than 4% by volume.
If the oxygen monitoring instrumentation is inoperable, operation of the waste gas holdup system may continue provided grab samples are collected in accordance with the Surveillance Frequency Control Program and analyzed within the following 4 hours.
SALEM - UNIT 2                                314 11-15                       Amendment No. 282

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6 SALEM - UNIT 2       3/4 11-18 Amendment No. 215

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3/4,1     A&&CITVnr CONTROL -SYS=EM BASES 3/4.1.1   BOMTIM- CONTROL 3/4.1.1.1 and 3/4.1.1.2 SNUTM       MGRt!
A sufficient S*IUTDOW M ZN ensures that 1) the eactor can be mad&
subczitical from all operating conditions, 2) the reactivity transients associated with postulated accident conditions are cont-ollable within acceptable limits, and 3) the reactor will be maintained sufficiently subcritical to preclude inadvoztent criticality in the shutdown condition.
SHOTDOCM M9RGYN requirements *a*y throughout crce life as a function of fuel depletion, RCS boron concentration, and RCS T,,. The most restrictive condition occurs at ROL, with Tw,, at no load operating temperature, and is associated with a postulated stea*  lize break accident and resulting uncontrolled RCS cooldown. In the analysis of this accident, a milium SHUTDOWN HXOZN of 1.3% hk/k is initially required to control the reactivity transient. Accordingly, the SHUTDOWN MRGIN requirement is based upon this limiting condition and is consistent with FSAR safety analysis assumptions.
With T.,, less than or equal to 200"F, the reactivity transients resulting from a .postulated steam line break cooldown a=r miniaal and a It Ak/k shutdown margin provides adequate protection.
3/4.1.1.3   MODERATOR TEGMPRATUE COZFFICIENT f=TC)
The limitations on MTC are provided to ensure that the value of this coefficient remains within the limiting condition assumed in the accident and transient analyses.
SALEM - UNIT 2                      D3/4 1,-1.           2.Aaendment No. 197

3/4.1 -RZACt!VITY          CQW-MTRO  SXSTE)M BASES 3/4.1.1.3        ?"D RATOR TDG:RATURE COEFFICZEIEM          Q=)     XContinued)
The MTC values of this specification are applicable to a specific set of plant condittions; accordingly, verification of KTC values at condit.ions other than those explicitly stated will require extrapolation to those conditions in order to permit an accurate comparison.                                           ...
The most negative NTC value equivalent to the most positive moderator density     coefficient       QDC),   was obtained by incrementally          correcting       the NC used in     the FSAM      analysis to nominal operating conditions.                These corrections involved:       (1)    a conversion   of the MCC used in     t.he rAR analysis          to its equivalent MTC,          based on the rate of change of moderator density with temperatur.        at RATED THERMAL POWER conditions,          and (2)   subtracting from this value the &#xfd;argest differences in MTC observed between ROL, all rods vithdrawn, RATED THERMk.AL POWER conditions, and those most adverse conditions of moderator temperature and pressure, rod insertion, axial power skewing, and xenon concentration that can occur in nomaUl operation and lead to a significantly more negative ZOL MTC at            RATED THEF4RML POWER.      These corrections         transformed the      C .value used in       the FSAR analysis into the limiting End Of Cycle Life (MOL) MTC value.          The 300 ppm surveillance limit MTC value represents a conservative value at           a core condition of 300 ppm equilibrium boron concentration that is obtained by correcting the limiting ROL MTC for burnup and born concentration.
The surveillance requirements for measurement of the MTC at the beginning and near the end of the fuel cycle are adequate to confirm that the MTC remains with Its limits since this coefficient changes slowly due principally to the reduction in RCS boron concentration associated with ual .burnup.
3/4.1.1.4          =n4NMU   TEMPERATUREM       CORI~TICALITY This specification ensures that the reactor will not be made critical with the Reactor Coolant System average temperature less than 541"F. This limitation is required to ensure 1) the moderator temperature coefficient is within its analyzed temperature range, 2) the protective instrumentation is within its normal operating range, 3) the P-12 interlock is above its allowable setpoint, 4) the pressurizer is capable of being in an OPERABL=
status with a steam bubble, and 5) the reactor pressure vessel is above its minimum RXT,        _&#xfd;tmperature-.
SALEM - UNIT 2                                  3 3/4 1-2                         Amendment Nc.197

REACTIVITY CONTROL SYSTEMS BASES 3/4.1.2   BORATION SYSTEMS The boron injection system ensures that negative reactivity control is available during each mode of facility operation. The components required to perform this function include:    1) borated water sources, 2) charging pumps,
: 3) separate flow paths, 4) boric acid transfer pumps, and 5) offsite power or an emergency power supply from OPERABLE diesel generators.
With the RCS average temperature &#x17d; 350'F, a minimum of two boron injection flow paths are required to ensure single functional capability in the event an assumed failure renders one of the flow paths inoperable. The boration capability of either flow path is sufficient to provide a SHUTDOWN MARGIN from expected operating conditions of 1.3% delta k/k after xenon decay and cooldown to 200'F. The maximum expected boration capability (minimum boration volume) requirement is established to conservatively bound expected operating conditions throughout core operating life. The analysis assumes that the most reactive control rod is not inserted into the core. The maximum expected boration capability requirement occurs at EOL from full power equilibrium xenon conditions and requires borated water from a boric acid tank in accordance with TS Figure 3.1-2, and additional makeup from either:
(1) the second boric acid tank and/or batching, or (2) a maximum of 41,800 gallons of 2,300 ppm borated water from the refueling water storage tank.
With the refueling water storage tank as the only borated water source, a maximum of 73,800 gallons of 2,300 ppm borated water is required.      However, to be consistent with the ECCS requirements, the RWST is required to have a minimum contained volume of 350,000 gallons during operations in MODES 1, 2, 3 and 4.
The boric acid tanks, pumps, valves, and piping contain a boric acid solution concentration of between 3.75% and 4% by weight. To ensure that the boric acid remains in solution, the tank fluid temperature and the process pipe wall temperatures are monitored to ensure a temperature of 63&deg;F, or above is maintained. The tank fluid and pipe wall temperatures are monitored in the main control room. A 5'F margin is provided to ensure the boron will not precipitate out.
Should ambient temperature decrease below 63&deg;F, the boric acid tank heaters, in conjunction with boric acid pump recirculation, are capable of maintaining the boric acid in the tank and in the pump at or about 63'F. A small amount of boric acid in the flowpath between the boric acid recirculation line and the suction line to the charging pump will precipitate out, but it will not cause flow blockage even with temperatures below 50'F.
With the RCS temperature below 350'F, one injection system is acceptable without single failure consideration on the basis of the stable reactivity condition of the reactor and the additional restrictions prohibiting CORE OPERATIONS and positive reactivity change in the event the single injection system becomes inoperable.
SALEM - UNIT 2                       B 3/4 1-3                    TSBC SCN 05-042

REACTIVITY CONTROL SYSTEMS BASES The boron capability required below 200 OF is sufficient to provide a SHUTDOWN MARGIN of 1% delta k/k after xenon decay and cooldown from 200 'F to 140 'F. This condition requires either 2,600 gallons of 6,560 ppm borated water from the boric acid storage tanks or 7,100 gallons of 2,300 ppm borated water from the refueling water storage tank.
The 37,000 gallons limit in the refueling water storage tank for Modes 5 and 6 is based upon 21,210 gallons that is undetectable due to lower tap location, 8,550 gallons for instrument error, 7,100 gallons required for shutdown margin, and an additional 140 gallons due to rounding up.
The limits on contained water volume and boron concentration of the RWST also ensure a pH value of between 7.0 and 10.0 for the solution recirculated within containment after a LOCA. This pH band minimizes the evolution of iodine and minimizes the effect of chloride and caustic stress corrosion on mechanical systems and components. The contained water volume limits include allowance for water not available because of discharge line location and other physical characteristics.
The OPERABILITY of one boron injection system during REFUELING ensures that this system is available for reactivity control while in MODE 6.
3/4.1.3   MOVABLE CONTROL ASSEMBLIES The specifications of this section ensure that (1) acceptable power distribution limits are maintained, (2) the minimum SHUTDOWN MARGIN is maintained, and (3) limit the potential effects of rod mis-alignment on associated accident analyses. OPERABILITY of the control rod position indicators is required to determine control rod positions and thereby ensure compliance with the control rod alignment and insertion limits. OPERABLE condition for the analog rod position indicators is defined as being capable of indicating rod position to within the allowed rod misalignment relative to the bank demand position for a range of positions. For the Shutdown Banks and Control Bank A this range is defined as the group demand counter indicated position between 0 and 30 steps withdrawn inclusive, and between 200 and 230 steps withdrawn inclusive. This permits the operator to verify that the control rods in these banks are either fully withdrawn or fully inserted, the normal operating modes for these banks. Knowledge of these banks' positions in these ranges satisfies all accident analysis assumptions concerning their position. The range for Control Bank B is defined as the group demand counter indicated position between 0 and 30 steps withdrawn inclusive, and between 160 and 230 steps withdrawn inclusive. For Control Banks C and D the range is defined as the group demand counter indicated position between 0 and 230 steps withdrawn. Comparison of the group demand counters to the bank insertion limits with verification of rod position with the analog rod position indicators (after thermal soak after rod motion) is sufficient verification that the control rods are above the insertion limits.      The full out position will be specified in the reload analysis for the cycle.      This position will be within the band established by FULLY WITHDRAWN and will be administratively controlled. This band is allowable to minimize RCCA wear, consistent with Information Notice 87-19 and RCCA examinations that were conducted during Salem Unit 2 Spring outage 2008 (2R16) by the Salem RCCA vendor AREVA NP (Refer to LAR S09-01).
SALEM - UNIT 2                  B 3/4 1-4                 Amendment No. 276 (PSEG Issued)

REACTIVITY CONTROL SYSTEMS BASES The ACTION statements which permit limited variation from the basic requirements are accompanied by additional restrictions which ensure that the original criteria are met. Mis-alignment of a rod requires measurement of peaking factors or a restriction in THERMAL POWER; either of these restrictions provide assurance of fuel rod integrity during continued operation. The reactivity worth of a mis-aligned rod is limited for the remainder of the fuel cycle to prevent exceeding the assumption used in the accident analysis.
The maximum rod drop time restriction is consistent with the assumed rod drop time used in the accident analyses. Measurement with Tavg >541OF and with all reactor coolant pumps operating ensures that the measured drop times will be representative of insertion times experienced during a reactor trip at operating conditions.
Control rod positions and OPERABILITY of the rod position indicators are required to be verified in accordance with the Surveillance Frequency Control Program with more frequent verifications required if an automatic monitoring channel is inoperable. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
The terms "Shutdown Rod Position Indicator," "Analog Rod Position Indicator," "Control Rod Position Indicator," and "Rod Position Indicator" are all used in this bases section or in Technical Specifications, and all refer to indication driven by the output of the Analog Rod Position Indication (ARPI) system.
One method for determining rod position are the indicators on the control console. An alternate method of determining rod position is the plant computer. Either the control console indicator or plant computer is sufficient to comply with this specification. The plant computer receives the same input from ARPI as the control console indicators and provides resolution equivalent to or better than the control console indicators. The plant computer also provides a digital readout of rod position which eliminates interpolation and parallax errors inherent to analog scales.
Rod demand position is indicated on the control console and the plant computer. The rod demand position is a digital signal, namely a pulse, and is generated each time the Rod Control System demands a rod position step change, one pulse for each rod step. The pulses are "counted" and displayed by the control console group demand step counters. There are two group demand step counters for each bank of rods with exception of shutdown banks C and D.
The plant computer also "counts" and displays the demand pulses. Only the group 1 demand position of each rod bank is displayed on the plant computer as only the group 1 pulses are routed to the plant computer. The group 1 demand position on the plant computer is, by default, called "Cont Bank A Steps" or "S/D Bank A Steps" etc. with no reference to group 1 or group 2.
As the plant computer receives the same demand pulses from the Rod Control System as the control console group demand step counters and provides equivalent resolution, the plant computer "bank step" display provides an alternate method of determining group 1 rod demand position. Either the control console group 1 demand step counter or the plant computer "bank step" display is sufficient to comply with this specification for group 1 rod demand position. Only the control console group 2 demand counter can be used to comply with the specification for group 2 rod demand.
SALEM - UNIT 2                                 B 3/4 1-5                        Amendment No. 282 (PSEG Issued)

3Z4.2 -P0-WR4-STR~tMflO        L~aTS BIASES The specifications of    this section provide assurance of fuel integrity during Condition I (Nomi        Operation) and 1I (Zcidents of Moderate Frequency) events by, (a)       o.etzg the D    Design Criteria during normal operation and n short to=     transients.,  and  (b) *1*it.inq the fission gas release, fuel pallet temperature and cladding mechanical properties to vithin assumed design criteria. In addition, limiting the peak linear power density during Condition I events provides assurance that the initial         conditions assumed for the LOCA.
analyses are met and the ZCCS acceptance c=iteria limit of 2200&deg;F ts not exceeded.
The definitions of hot channel factors as used in        these specrifications are as follows:
Fr(Z)        Heat Flux Hot Channel Factor, is dafined as the maximum local beat flux on the surface of a fuel rod at core elevation Z divided by the average fuel rod heat flux, allowing for manufacturing tolerances on fuel pellets and rods.
F*          Nuclear Enthalpy Rise Hot Channel Factor, is defined as the ratio of the integral of linear power along the rod with the highest integrated power to the average rod power.
F. (Z)       Radial Peaking Factor is defined as the ratio of peak power density to average power density in the horizontal plane at core elevation Z.
3/4.2.1    AXIAL FLUX DITERENCE      (AFD)
The Il~.its on AXIAL F=,U DIFE UNCE-assure that the F0 (Z) upper bound envelope of the Fr limit specified in the CORE OPERATING LIMITS REPORT (COLR) times the normalized axial peaking factor is' not exceeded during either normal operation or in the event of xenon redistribution following power changes.
Target flux difference is determined at equilibriua xenon conditions with the part length control rods withdLawn from the core. The full length rods may be positioned within the core in       accordance with their respective insertion li&#xfd;iits and should be inserted neam their normal position for steady state operation at high power levels. The value of the target flux difference obtained under these conditions divided by the fraction of RATED "THZM.L POWER is the -target flux difference at RATED THWROAL POWER for the associated core burnup eonditions. Target flux differences for other THErM-L P0IER levels are obtained by *ultiplying the RATED TIEC9aL PM            valu*e by the appropriate fractional THERMAL POWER level.         The periodic updating of the target flux difference value is necessary to reflect core burnup considerations.
SALEM - UNIT 2                             B 3/4 2-1              Amendment No. 197

POWER. DISTRIBUTION LRhaTS BASE S Although it is intended that the plant will be operated with the AXZAL FLUX DIFFEZNCE within the target band in the COLR per Specification 3.2.1 about the target flux difference, d%ring rapid plant THZRMOL POWER reductions, control rod notion will cause the APD to deviate outside of the target band at reduced THERML POWER levels. This deviation will not affect the xenon redistribution sufficiently to change the envelope of peaking factors which may be reached on a subsequent return to RATED THER1 4 L POWER (with the APD within the target    band) provided the time duration of the deviation is limited. Accordingly, a 1 hour penalty deviation flmit cumulative during the previous 24 hours is provided for operation outside of the target band but within the limits specified in the COLR while at THER14hL POWER levels between 50% and 90% of RATED THERMAL POWER. For TER)MAL POWER levels between 15% and 50% of rated THERMAL POWER, deviations of the AFD outside of the target band are less significant. The penalty of 2 hours actual time reflects this reduced significance.
Provisions for monitoring the AFD are derived from the plant nuclear instrumentation system through the AFD Monitor Alarm. A control room recorder continuously displays the auctioneered high flux difference and the target band limits as a function of power level. An alarm is received any time the auctioneezed high flux difference exceeds the target band limits.      Time outside the target band is graphio4lly presented on the strip chart.
Figure B 3/4 2-1 shows a typical monthly target band.
SAL.EM -  UXIT 2                     B 3/4 3/2- 2-2            Amendment No.197

MZFOa@TZON ON~LY*
Percent of Rated Thermal Power 100%
90%
80%
70%
Flux 0*%mnm 40%
30%
0
                    -2( 96     .-10%          0        10%        20%
INDICATED AXIAL FLUX DIFFERENCE rlgureo  3JM 2-1    TYPICAL INDICATED AXIAL FLUX DIFFERENCE VERSUS THERMAL POWER a
* xzFZR To cCLI rzGMP     2 MR1 ACT=A  LIMTS SALM - MZT 2                         ]3 3/4 2-3                 - ?~Z SALZ          No. 197 2 33/42-3Amenctagt

POWER DISTR:3UTIrON LIMITS BASES 3/4.2.2 and 3/4.2.3    HEAT FLUX AND NUCLEAR ENTHALPY HOT CHANNEL AND RADIAL PEAKING FACTORS - F 0 (Z) AND F The limits on heat flux and nuclear enthalpy hot channel factors and RCS flow rate ensure that 1) the design limits on peak local power density and minimum DNBR are not exceeded and 2) in the event o: a LOCA the peak fuel clad temperature will not exceed the 2200OF ECCS acceptance criteria limit.
Each of these hot channel factors are measurable but will normally only be determined periodically as specified in Specifications 4.2.2 and 4.2.3.
This periodic surveillance is sufficient to insure that the limits are maintained provided:
: a. Control rod in a single group move together with no individual rod insertion differing from the group demand position by more than the allowed rod misalignment.
: b. Control rod groups are sequenced with overlapping groups as described in Specification 3.1.3.5.
: c. The control rod insertion limits of Specifications 3.1.3.4 and 3.1.3.5 are maintained.
: d. The axial power distribution, expressed in terms of AXIAL FLUX DIFFERENCE, is maintained within the limits.
The relaxation in        as a function of THERMAL POWER allows changes in the radial power shape for all permissible rod insertion limits.      FN    will be maintained within its     limits provided conditions a through d above, are maintained.
When an Fg measurement is taken. both experimental error and manufacturing tolerance must be allowed for.      Five percent is the appropriate allowance for a full core map taken with the incore detector flux mapping system and 3% is the appropriate allowance for manufacturing tolerance.        For measurements obtained using the Power Distribution Monitoring System (PDMS),
the appropriate measurement uncertainty is determined using the measurement uncertainty methodology contained in WCAP 12472-P-A. The cycle and plant uncertainty calculation information needed to support the PDMS calculation is contained in the COLR. The PDMS will automatically calculate and apply the correct measurement uncertainty, and apply a 3% allowance for manufacturing tolerance.
When F Na is measured, experimental error must be allowed for and is obtained from the COLR when using the PDMS or the incore detection system.
The specified limit for Fe6H also contains an 8% allowance for uncertainties which mean that normal operation will result in F*a I FX'4 l.08. Where          PT H is the limit at RATED THERMAL POWER (RTP) specified in the CORE OPERATING LIMITS REPORT (COLR). The 8% allowance is based on the following considerations; SALEM - UNIT 2                        B 3/4 2-4                  Amendment No. 218

BASES 3/4.2.2 and 3/4.2.3    HEAT FLUX AND NUCLEAR ENTHALPY HOT CHANNEL AND N
RADIAL PEAKING FACTORS - F9(Z) AND F&#xfd;, (Continued)
: a. abnormal perturbations in the radial power shape,      such as from rod misalignment,    effect FN    more directly than FQ.
: b. although rod movement has a direct influence upon limiting Fq to within its limit, such control is not readily available to limit N
FH , and c-  errors in prediction for control power shape detected during startup physics test can be compensated for in Fg by restricting axial flux distributions.      This compensation for F     is less rapidly available.
The appropriate measurement uncertainty for FNAK obtained using PDMS is determined using the measurement uncertainty methodology contained in WCAP 12472-P-A. The cycle and plant specific uncertainty information needed to support the PDMS calculation is     contained in  the COLR. The PDMS will automatically calculate and apply the correct measurement uncertainty to the measured *4H.
The radial peaking factor Fx(Z) is      measured periodically to provide assurance that the hot channel factor Fg(Z,      remains within its limit. The Fxy limit for RATED THERMAL POWER F        , as provided in COLR per specification
                                ,TPxy 6.9.1.9, was determined from expected power control maneuvers over the full range of burnup conditions in the core.
3/4.2.4 QUADRANT POWER TILT RATIO The quadrant power tilt   ratio limit assures that the radial power distribution satisfies the design values used in the power capability analysis. Radial power distribution measurements are made during startup testing and periodically during power operation.
SALEM - UNIT 2                        B 3/4 2-5                   Amendment No. 218

POWER DISTRIBUTION LIMITS BASES The limit of 1.02 at which corrective action is required provides DNB and linear heat generation rate protection with x-y plane power tilts. A limiting tilt of 1.025 can be tolerated before the margin for uncertainty in FQ is depleted. The limit of 1.02 was selected to provide an allowance for the uncertainty associated with the indicated power tilt.
The 2 hour time allowance for operation with a tilt condition greater than 1.02 but less than 1.09 is provided to allow identification and correction of a dropped or misaligned rod. In the event such action does not correct the tilt, the margin for uncertainty on FQ is reinstated by reducing the power by 3% from RATED THERMAL POWER for each percent of tilt in excess of 1.0.
3/4.2.5 DNB PARAMETERS The limits on the DNB related parameters assure that each of the parameters are maintained with the normal steady state envelope of operation assumed in the transient and accident analyses. The limits are consistent with the initial FSAR assumptions and have been analytically demonstrated adequate to maintain a minimum DNBR of the design DNBR value throughout each analyzed transient.
The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
SALEM - UNIT 2                                 B 3/4 2-6                         Amendment No. 282 (PSEG Issued)

3/4.3 INSTRUMENTATION BASES 3/4.3.1 and 3/4.3.2 PROTECTIVE AND ENGINEERED SAFETY FEATURES (ESF)
INSTRUMENTATION The OPERABILITY of the protective and ESF instrumentation systems and interlocks ensure that 1) the associated ESF action and/or reactor trip will be initiated when the parameter monitored by each channel or combination thereof exceeds its setpoint, 2) the specified coincidence logic and sufficient redundancy is maintained to permit a channel to be out of service for testing or maintenance consistent with maintaining an appropriate level of reliability of the Reactor Protection and Engineered Safety Features instrumentation and, 3) sufficient system functional capability is available from diverse parameters.
The OPERABILITY of these systems is required to provide the overall reliability, redundance and diversity assumed available in the facility design for the protection and mitigation of accident and transient conditions. The integrated operation of each of these systems is consistent with the assumptions used in the accident analyses.
The Trip Setpoints are the nominal values at which the bistables are set. Any bistable is considered to be properly adjusted when the "as-left" value is within the band for CHANNEL CALIBRATION accuracy (i.e., +/- rack calibration + comparator setting accuracy).
The Trip Setpoints used in the bistables are based on the analytical limits stated in the UFSAR.
The selection of these Trip Setpoints is such that adequate protection is provided when all sensor and processing time delays are taken into account. To allow for calibration tolerances, instrumentation uncertainties, instrument drift, and severe environment errors for those Reactor Protection System (RPS) channels that must function in harsh environments as defined by 10 CFR 50.49, the Trip Setpoints and Allowable Values specified in the Technical Specification Limiting Conditions for Operation (LCO's) are conservatively adjusted with respect to the analytical limits. The methodology used to calculate the Trip Setpoints is consistent with Instrument Society of America standard ISA-$67.04-1982, which is endorsed via NRC Regulatory Guide 1.105, Rev. 2. The actual nominal Trip Setpoint entered into the bistable is more conservative than that specified by the Allowable Value to account for changes in random measurement errors detectable by a CHANNEL FUNCTIONAL TEST. One example of such a change in measurement error is drift during the surveillance interval. If the measured setpoint does not exceed the Allowable Value, the bistable is considered OPERABLE.
Setpoints in accordance with the Allowable Value ensure that the safety analyses which demonstrate that safety limits are not violated remain valid (provided the unit is operated within the LCO's at the onset of any design basis event and the equipment functions as designed).
The Trip Setpoints and Allowable Values listed in the LCO's incorporate all of the known uncertainties applicable for each channel. The magnitudes of these uncertainties are factored into the determination of each Trip Setpoint. All field sensors and signal processing equipment for these channels are assumed to operate within the allowances of these uncertainty magnitudes.
The surveillance requirements specified for these systems ensure that the overall system functional capability is maintained comparable to the original design standards. The periodic surveillance tests are sufficient to demonstrate this capability. The Surveillance Frequency is SALEM - UNIT 2                                B 3/4 3-1                        Amendment No. 282 (PSEG Issued)

INSTRUMENTATION BASES based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program. Specified surveillance and maintenance outage times have been determined in accordance with WCAP-10271, "Evaluation of Surveillance Frequencies and Out of Service Times for the Reactor Protection Instrumentation System," and Supplements to that report. Out of service times were determined based on maintaining an appropriate level of reliability of the Reactor Protection System and Engineered Safety Features instrumentation.
The verification of response time provides assurance that the reactor trip and the engineered safety features actuation associated with each channel is completed within the time limit assumed in the safety analysis. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program. Response time acceptance criteria have been relocated to UFSAR Section 7.2 tables and 7.3 tables. No credit is taken in the analysis for those channels with response times indicated as not applicable (i.e., N.A.). The Note 8 response times for feedwater isolation are based on WCAP-16503, "Salem Unit 1 and Unit 2 Containment Response to LOCA and MSLB for Containment Fan Cooler Unit (CFCU) Margin Recovery Project," Revision 3, (LCR S06-10).
SGFP trip and FIV closure are credited in the containment analyses for LOCA and MSLB in case an FRV fails open.
Response time may be verified by actual response time tests in any series of sequential, overlapping or total channel measurements, or by the summation of allocated sensor response times with actual response time tests on the remainder of the channel. Allocations for sensor response times may be obtained from: (1) historical records based on acceptable response time tests (hydraulic, noise, or power interrupt tests), (2) inplace, onsite, or offsite (e.g. vendor) test measurements, or (3) utilizing vendor engineering specifications. WCAP-13632-P-A, Revision 2, "Elimination of Pressure Sensor Response Time Testing Requirements" provides the basis and methodology for using allocated sensor response times in the overall verification of the channel response time for specific sensors identified in the WCAP. Response time verification for other sensor types, and other components that do not have plant-specific NRC approval to use alternate means of verification, must be demonstrated by test.
The allocation for sensor response times must be verified prior to placing the component in operational service and re-verified following maintenance that may adversely affect response time. In general, electrical repair work does not impact response time provided the parts used for repair are of the same type and value. One example where response time could be affected is replacing the sensing assembly of a transmitter.
Channel testing in a bypassed condition shall be performed without lifting leads or jumpering bistables.
3/4.3.3 MONITORING INSTRUMENTATION 3/4.3.3.1 RADIATION MONITORING INSTRUMENTATION The OPERABILITY of the radiation monitoring channels 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.
SALEM - UNIT 2                                 B 3/4 3-1a                          Amendment No. 282 (PSEG Issued)

INSTRUMENTATION BASES 3/4.3.3.1 RADIATION MONITORING INSTRUMENTATION (Continued)
In the postulated Fuel Handling Accident, the revised dose calculations, performed using 10 CFR 50.67 and Regulatory Guide 1.183, Alternative Source Term, do not take credit for automatic containment purge isolation thus allowing for continuous monitoring of containment activity until containment closure is achieved. If required, containment purge isolation can be initiated manually from the control room.
CROSS REFERENCE - TABLE 3.3-6 T/S Table       Instrument Description                                       Acceptable RMS Item No.                                                                     Channels la              Fuel Storage Area                                            2R5 or 2R9 1b              DELETED 2ala            Containment Gaseous Activity Purge & PressureNacuum          2R12A or 2R41A, Relief Isolation                                             B and D(1) (2) 2alb            Containment Gaseous Activity RCS Leakage Detection           2R12A 2a2a             (NOT USED) 2a2b            Containment Air Particulate Activity RCS Leakage             2R11A Detection 2bl             Noble Gas Effluent Medium Range Auxiliary Building           2R45B(3)
Exhaust System (Plant Vent) 2b2             Noble Gas Effluent High Range Auxiliary Building             2R45C(37 Exhaust System (Plant Vent) 2b3             Noble Gas Effluent Condenser Exhaust System                  2R15 3a              Unit 2 Control Room Intake Channel 1 (to Unit 2 Monitor)     2R1 B-1 Unit 2 Control Room Intake Channel 2 (to Unit 1 Monitor)     1R1 B-2 Unit 1 Control Room Intake Channel 1 (to Unit 1 Monitor)     1R1B-1 Unit 1 Control Room Intake Channel 2 (to Unit 2 Monitor)     2R1B-2 (1)     The channels listed are required to be operable to meet a single operable channel for the Technical Specification's "Minimum Channels Operable" requirement.
(2)     For Modes 1, 2, 3, 4 & 5, the setpoint applies to 2R41 D per Specification 3.3.3.9.
The measurement range applies to 2R41A and B which display in pCi/cc using the appropriate channel conversion factor from cpm to pCi/cc.
(3)     If 2R45 is out of service 2R41 may be used to meet the technical specification action requirement.
SALEM UNIT 2                                   B 3/4 3-2                       Amendment No. 282 (PSEG Issued)

INSTRUMENTATION BASES Immediate action(s),   in  accordance with the LCO Action Statements,    means that the required action should be pursued without delay and in      a controlled manner.
3/4.3.3.2 THIS SECTION DELETED 3/4.3.3,3 THIS SECTION DELETED 3/4.3.3.4 THIS SECTION DEL.IETED 3/4.3.3.5    REMOTE SHUTDOWN INSTRUMENTATION The OPERABILITY of the remote shutdown instrumentation ensures that sufficient capability is available to permit shutdown arid maintenance of HOT STANDBY of the facility   from locat:ions outside of the control room. This capability is required in the event control room habitability is lost    and is consistent with General Design Ci:iterion [19 of 10 CIR 50.
3/4.3.3.6 THIS SECTION DELETED 3/4.3.3.7    ACCIDENT MONITORING INSTRUMENTATION The OPERABILITY of the accident monitoring instrumentation ensures that sufficient information is available on selected plant parameters to monitor and assess these variables following an accident. This capability is consistent with the Recommendations of Regulatory Guide     -..97, "Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant Conditions During and Following an Accident," December 1975 and NUREG-057B,"TMI-2 Lessons Learned Task Force Status Report and Short-Term Recommendations."
SALEM - UNIT 2                        B 3/4 3-3                  Amendment No. 265 (PSEG Issued)

INSTRUMENTATION BASES 3/4.3.3.8  RADIOACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION
&#xfd;The purpose of tank level indicating devices is to assure the detection and control of leaks that if not controlled could potentially result in the transport of radioactive materials to UNRESTRICTED AREAS.
3/4.3.3.9 THIS SECTION DELETED 3/4.3.3.10 THIS SECTION DELETED 3/4.3.3.11 THIS SECTION DELETED 3/4.3.3.12 THIS SECTION DELETED 3/4.3.3.13 THIS SECTION DELETED SALEM - UNIT 2                      B 3/4 3-3a              Amendment No. 265 (PSEG Issued)

INSTRUMENTATION BASES 3/4.3.4 Deleted 3/4.3.3.14 POWER DISTRIBUTION MONFTORING SYSTEM (PDMS)
The Power Distribution Monitoring System (PDMS) provides core monitoring of the limiting parameters. The PDMS continuous core power distribution measurement methodology begins with the periodic generation of a highly accurate 3-D nodal simulation of the current reactor power distribution. The simulated reactor power distribution is then continuously adjusted by nodal and thermocouple calibration factors derived from an incore power distribution measurement obtained using the incore movable detectors to produce a highly accurate power distribution measurement. The nodal calibration factors are updated in accordance with the Surveillance Frequency Control Program. Between calibrations, the fidelity of the measured power distribution is maintained via adjustment to the calibrated power distribution provided by continuously input plant and core condition information. The plant and core condition data utilized by the PDMS is cross checked using redundant information to provide a robust basis for continued operation. The loop inlet temperature is generated by averaging the respective temperatures from each of the loops, excluding any bad data. The core exit thermocouples provide many readings across the core and by the nature of their usage with the PDMS, smoothing of the measured data and elimination of bad data is performed with the Surface Spline fit. PDMS uses the NIS Power Range excore detectors to provide information on the axial power distribution. Hence, the PDMS averages the data from the four Power Range excore detectors and eliminates any bad excore detector data.
SALEM - UNIT 2                               B 3/4 3-4                       Amendment No. 282 (PSEG Issued)

INSTRUMENTATION BASES The bases for the operability requirements of the PDMS is to provide assurance of the accuracy and reliability of the core parameters measured and calculated by the PDMS core power distribution monitor function. These requirements fall under four categories:
: 1.      Assure an adequate number of operable critical sensors.
: 2.      Assure sufficiently accurate calibration of these sensors.
: 3.      Assure an adequate calibration database regarding the number of data sets.
: 4.      Assure the overall accuracy of the calibration.
The minimum number of required plant and core condition inputs include the following:
: 1.      Control Bank Positions.
: 2.      At least 50% of the cold leg temperatures.
: 3.      At least 75% of the signals from the power range excore detector channels (comprised of top and bottom detector section).
: 4.      Reactor Power Level.
: 5.      A minimum number and distribution of operable core exit thermocouples.
: 6.      A minimum number and distribution of measured fuel assembly power distribution information obtained using the incore movable detectors is incorporated in the nodal model calibration information.
The sensor calibration of Items 1, 2, 3, and 4 above are covered under other specifications.
Calibration of the core exit thermocouples is accomplished in two parts. The first being a sensor specific correction to K-type thermocouple temperature indications based on data from a cross calibration of the thermocouple temperature indications to the average RCS temperature measured via the RTDs under isothermal RCS conditions. The second part of the thermocouple calibration is the generation of thermocouple flow mixing factors that cause the radial power distribution measured via the thermocouples to agree with the radial power distribution from a full core flux map measured using the incore movable detectors. This calibration is updated in accordance with the Surveillance Frequency Control Program.
The operability requirements previously contained in Specification 3.3.3.2 have been moved to UFSAR Section 7.7.2.8 as part of Amendment 265.
SALEM - UNIT 2                                 B 3/4 3-5                      Amendment No. 282 (PSEG Issued)

ail mliImaileuu  UB   li    illiita aEU.U tm.BllaSUU  IIUi    3333   allllOl    lDlllI u.Ema.m      lBllltnm      m  iNa lmm a. mammina.ll 3/4.4..1           REACTOR           -"O.A,'     MEE AMD COOLANT C:ZRCA-TZOM The plant is               designed to operate with all reactor coolant loops in operation, meet the DNB design criteria                                 during all normal operations and anticipated transients. In MOD!S 1 and 2 with less than all coolant loops in operation, this                    specification requires that               the plant be in at least               ROT STANDYB witin                 1 hour.
Zn MODZ 3, a single reactor coolant loop provides sufficient                                       heat removal for removing decay heats but, single failure considerations require all                                                loops be in operation whenever the rod control system is energized and at least                                                  one loop be in operation when the rod control system is deenergized.
Zn MODX 4, a single reactor coolant loop or RIM loop provides sufficient heat removal for removing decay beat; but, single failure considerations require that at least                       2 loops be OPERABLZ.             Thus, if the reactor coolant loops are not OPERABLE,                      this specification requires that two RER                      loops be OPR.ABLE.
in    MODE 5,          single failure        considerations require that two RER loops be OPIRA3LE.                For support systems: Service Water (SW)                       and Component Cooling (CC),
component redundancy is                        necessary to ensure no single active component failure will cause the lee of Decay Heat Removal.                                    One piping path of SW and CC is adequate when it supports both RER loops.                                   The support systems needed before entering into the desired configuration (e.g., one service water loop out for maintenance in Modes 5 and 6) are controlled by procedures, and include the following:
* A requirement that two RNR, two CC and two SW pumps, powered from two different vital                   buses be kept operable
              # A listing             of the active (air/motor operated) valves in the affected flow path to be locked open or disabled Note tbhat             our tilled       reactor coolant loops,-with at least                  two steam generators v-th at least their                           secondary_ side water level greater than or equal to 5% (narrow range]) may be substituted for one residual heat removal loop.            This ensures that a single failure does not cause a loss of decay heat removal.
The operation of one Reactor Coolant pum                               or one  ME Pump provides adequate flow to ensure mixing, prevent stratification                                     and produce gradual reactivity changes--during moron concentration reductions in                                          the Reactor Coolant System.                      The reactivity       change rate associated with Boron concentration reductions will,                           therefore, be within the capability of operator recognition and conMtrol.
            .he restrictions               on starting a Reactor Coolant Pum below P-7 with one or more RCS cold legs less than or equal to 312"F are provided to prevent RCS pressure transients, caused by energy additions from the secondary system.
which could exceed the limits of Appendix 0 to 10MR Part 50.                                             The RCS will be protected against overpressure transients and will not exceed the limits of Appendix G by either (1) restricting                              the water volue in the pressurizer thereby providing a volume into which the primary coolant cam expand,                                             or (2) by restricting                the starting           of Reactor Coolant Px=Pa to those times when secondary water temperature in each steam generator is less than 50"? above each of the xCS cold leg temperatures.
s AL=         -     CIZT   2                                     a 3/4 4-1                           Amendment No.        197

REACTOR COOLANT SYSTEM BASES 3/4.4.2 and 3/4.4.3 SAFETY VALVES The pressurizer code safety valves operate to prevent the RCS from being pressurized above its Safety Limit of 2735 psig. Each safety valve is designed to relieve 420,000 pounds per hour of saturated steam at the valve setpoint. The relief capacity of a single safety valve is adequate to relieve any overpressure condition which could occur during shutdown. In the event that no safety valves are OPERABLE, an operating RHR loop, connected to the RCS, provides overpressure relief capability and will prevent RCS overpressurization. In addition, the Overpressure Protection System provides a diverse means of protection against RCS overpressurization at low temperature. While in Mode 5 the safety valve requirement may be met by establishing a vent path of equivalent relieving capacity when no code safety valves are OPERABLE.
During operation, all pressurizer code safety valves must be OPERABLE to prevent the RCS from being pressurized above its safety limit of 2735 psig. The combined relief capacity of all of these valves is greater than the maximum surge rate resulting from a complete loss of load assuming no reactor trip until the first Reactor Protective System trip setpoint is reached (i.e., no credit is taken for a direct reactor trip on the loss of load) and also assuming no operation of the power operated relief valves or steam dump valves.
Demonstration of the safety valves lift settings will occur only during shutdown and will be performed in accordance with the provisions of Section XI of the ASME Boiler and Pressure Code.
Surveillance testing allows a +/- 3% lift setpoint tolerance. However, to allow for drift during subsequent operation, the valves must be reset to within +/- 1% of the lift setpoint following testing.
3/4.4.4 PRESSURIZER The limit on the maximum water volume in the pressurizer assures that the parameter is maintained within the normal steady-state envelope of operation assumed in the SAR. The limit is consistent with the initial SAR assumptions. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program. The maximum water volume also ensures that a steam bubble is formed and thus the RCS is not a hydraulically solid system. The requirement that a minimum number of pressurizer heaters be OPERABLE enhances the capability of the plant to control RCS pressure and establish natural circulation.
3/4.4.5 RELIEF VALVES The OPERABILITY of the PORVs and block valves is determined on the basis of their being capable of performing the following functions:
A. Manual control of PORVs to control reactor coolant system pressure. This is a function that is used for the steam generator tube rupture accident and for plant shutdown.
SALEM - UNIT 2                                  B 3/4 4-2                       Amendment No. 282 (PSEG Issued)

REACTOR COOLANT SYSTEM BASES 3/4.4.5     RELIEF VALVES   (continued)
B. Automatic control of PORVs to control reactor coolant system pressure. This is a function that reduces challenges to the code safety valves for overpressurization events, including an inadvertent actuation of the Safety Injection System.
C. Maintaining the integrity       of the reactor coolant pressure boundary.      This is a function that is related to controlling identified leakage and ensuring the ability    to detect unidentified reactor coolant pressure boundary leakage.
D. Manual control of the block valve to : (1) unblock an isolated PORV to allow it to be used for manual and automatic control of Reactor Coolant System pressure (Items A & B), and (2) isolate a PORV with excessive seat leakage (Item C).
E. Manual control of a block valve to isolate        a stuck-open PORV.
3/4.4.6      STEAM GENERATOR    (SG) TUBE INTEGRITY The LCO requires that SG tube integrity be maintained.          The LCO also requires that all  SG tubes that satisfy the repair criteria        be plugged in accordance with the Steam Generator Program.
During an SG inspection, any inspected tube that satisfies          the Steam Generator Program repair criteria       is removed from service by plugging.      If a tube was determined to satisfy      the repair criteria    but was not plugged, the tube may still have tube integrity.
In the context of this      Specification, a SG tube is defined as the entire length of the tube, including the tube wall, between the tube-to-tubesheet weld at the tube inlet and the tube-to-tubesheet weld at the tube outlet.           The portion of the tube within the hot-leg tubesheet region below the W* distance is excluded.            The excluded portion of the tube defined by W* is ONLY applicable to Westinghouse Model 51 SGs with mill annealed Alloy 600 tubing expanded into the tubesheet using the Westinghouse explosive tube expansion (WEXTEX)         process. The tube-to-tubesheet weld is  not considered part of the tube.
A SG tube has tube integrity when it         satisfies the SG performance criteria. The SG performance criteria     are defined in Specification 6.8.4.i,      "Steam Generator (SG)
Program," and describe acceptable SG tube performance.          The Steam Generator Program also provides the evaluation process for determining conformance with the SG performance criteria.
There are three SG performance criteria:          structural integrity, accident induced leakage, and operational leakage.         Failure to meet any one of these criteria is considered failure to meet the LCO.
SALEM - UNIT 2                             B 3/4 4-3                 Amendment No. 262 (PSEG Issued)

REACTOR COOLANT    SYSTEM BASES The structural integrity       performance criterion provides a margin of safety against tube burst or collapse under normal and accident conditions, and ensures structural integrity    of the SG tubes under all    anticipated transients included in the design specification. Tube burst is defined as, "The gross structural failure of the tube wall. The condition typically corresponds to an unstable opening displacement (e.g., opening area increased in response to constant pressure) accompanied by ductile (plastic)      tearing of the tube material at the ends of the degradation."
Tube collapse is defined as, "For the load displacement curve for a given structure, collapse occurs at the top of the load versus displacement curve where the slope of the curve becomes zero."         The structural integrity      performance criterion    provides guidance on assessing loads that significantly affect burst or collapse. In that context, the term "significant" is defined as, "An accident loading condition other than differential        pressure is considered significant when the addition of such loads in the assessment of the structural integrity performance criterion could cause a lower structural limit or limiting burst/collapse condition to be established."          For tube integrity      evaluations, except for circumferential degradation, axial thermal loads are classified                as secondary loads.      For circumferential degradation, the classification          of axial thermal loads as primary or secondary loads will be evaluated on a case-by-case basis.      The division between primary and secondary classifications will be based on detailed analysis and/or testing.
Structural integrity requires that the primary membrane stress intensity              in a tube not exceed the yield strength for all        ASME Code, Section III,       Service Level A (normal operating conditions) and Service Level B (upset or abnormal conditions) transients included in the design specification.          This includes safety factors and applicable design basis loads based on ASME Code, Section III,              Subsection NB and draft Reg. Guide 1.121.
The accident induced leakage performance criterion ensures that the primary-to-secondary leakage caused by a design basis accident, other than a steam generator tube rupture (SGTR), is within the accident analysis assumptions.               The accident analysis assumes that accident induced leakage does not exceed 1 gpm per SG.                 The accident induced leakage rate includes any primary-to-secondary leakage existing prior to the accident in addition to primary-to-secondary leakage induced during the accident.
The operational leakage performance criterion provides an observable indication of SG tube conditions during plant operation.          The limit on operational leakage is contained in LCO 3.4.7.2, "Operational Leakage," and limits primary-to-secondary leakage through any one SG to 150 gallons per day.          This limit is based on the assumption that a single crack leaking this amount would not propagate to a SGTR under the stress conditions of a LOCA or a main steam line break.               If this amount of leakage is due to more than one crack, the cracks are very small, and the above assumption is conservative.
The ACTION requirements are modified by a Note clarifying that the Actions may be entered independently for each SG tube.          This is acceptable because the Action requirements provide appropriate compensatory actions for each affected SG tube.
Complying with the Action requirements may allow for continued operation, and subsequent affected SG tubes are governed by subsequent Action requirements.
SALEM - UNIT 2                             B 3/4 4-3a                   Amendment No. 262 (PSEG Issued)

REACTOR COOLANT                   SYSTEM BASES If     it    is     discovered that                   one or more SG tubes examined in an inservice                                             inspection satisfy           the      tube repair              criteria        but were not plugged in accordance with the Steam Generator Program, an evaluation                                     of SG tube integrity                   of the        affected            tube(s)          must be made.               Steam generator                  tube integrity          is      based on meeting the SG performance criteria            described in the Steam Generator Program.                                           The SG repair                criteria            define limits          on SG tube that                  allow for           flaw growth between inspections                              while still providing assurance that                               the SG performance criteria                         will       continue to be met.                         In order to determine if                            a SG tube that              should have been plugged has tube integrity, an evaluation                  must be completed that                        demonstrates that                 the SG performance criteria will       continue to be met until                             the next refueling                 outage or SG tube inspection.                                    The tube integrity                  determination is                   based on the estimated condition                               of the          tube at          the time the             situation            is     discovered and the estimated                          growth of the degradation                              prior to the next SG tube inspection.                                     An action         time of 7 days is                   sufficient              to     complete the evaluation                  while minimizing the risk                        of plant            operation           with a SG tube that                        may not have tube integrity.                                 If the evaluation               determines that                 the affected                 tube(s) have tube integrity,                          plant        operation         is allowed to continue until                            the next refueling             outage or SG inspection                         provided the inspection                       interval           continues to be supported by an operational                                 assessment that             reflects          the affected              tubes.             However, the affected                 tube(s)          must be plugged prior                    to entering             HOT SHUTDOWN following the next refueling                   outage or SG inspection.                        This allowed outage time is                                acceptable since operation                    until         the next inspection                is     supported by the operational assessment.
If     SG tube integrity                      is    not being maintained or the Action requirements are not met, the             reactor         must be brought to HOT STANDBY within                                     6 hours and COLD SHUTDOWN within 36 hours.                        The action            times are reasonable based on operating                                       experience, to reach the              desired          plant       conditions from full                   power conditions                  in    an orderly               manner and without challenging plant                                   systems.
During shutdown periods                             the SGs are inspected                    as required             by surveillance requirements and the Steam Generator Program.                                                  NEI 97-06, "Steam Generator Program Guidelines,"                 and its          referenced EPRI Guidelines, establish                                    the content of the Steam Generator Program.                          Use of the Steam Generator Program ensures that                                               the      inspection is     appropriate              and consistent                  with accepted industry                     practices.
During SG inspections                           a condition monitoring assessment of the                                       SG tubes is performed.                 The condition                monitoring assessment determines the "as found" condition of the SG tubes.                        The purpose of the condition                          monitoring assessment is                             to     ensure that       the       SG performance criteria                         have been met for                 the    previous operating                        period.
The Steam Generator Program determines the                                            scope of the inspection                          and the methods used to            determine whether the tubes contain                                   flaws satisfying                  the     tube repair criteria.                Inspection             scope (i.e.,             which tubes or areas of tubing within the SG are to be inspected)                     is     a function of existing                    and potential               degradation locations.
The Steam Generator Program also                                     specifies        the      inspection           methods to be used to find       potential            degradation.                  Inspection        methods are a function                         of degradation morphology, nondestructive                                 examination (NDE) technique capabilities                                       and inspection locations.                 The Frequency is                   determined by the operational                            assessment and other limits          in     the     SG examination guidelines.
SALEM -           UNIT 2                                                   B 3/4   4-3b                                             Amendment No.                   262 (PSEG        Issued)

REACTOR COOLANT SYSTEM BASES The Steam Generator Program uses information on existing degradations and growth rates to determine an inspection Frequency that provides reasonable assurance that the tubing will meet the SG performance criteria       at the next scheduled inspection.
In addition, Specification 6.8.4.i      contains prescriptive requirements concerning inspection intervals to provide added assurance that the SG performance criteria will be met between scheduled inspections.
During an SG inspection, any inspected tube that satisfies        the Steam Generator Program repair criteria     is removed from service by plugging.       The tube repair criteria  delineated in Specification 6.8.4.i      are intended to ensure that tubes accepted for continued service satisfy      the SG performance criteria     with allowance for error in size measurement and future growth.        In addition, the tube repair criteria,  in conjunction with other elements of the Steam Generator Program, ensure that the SG performance criteria      will continue to be met until     the next inspection of the subject tube(s).       NEI 97-06 provides guidance for performing operational assessments to verify that the tubes remaining in service will continue to meet the SG performance criteria.       The Frequency of prior to entering HOT SHUTDOWN following a SG inspection ensures that the Surveillance has been completed and all          tubes meeting the repair criteria      are plugged prior to subjecting the SG tubes to significant primary-to-secondary pressure differential.
License Change Request (LCR) S05-07 (LR-N05-0397, LR-N06-0277, LR-N06-0338) provides requirements for limited tubesheet inspection that is only applicable within the hot leg WEXTEX expanded region of the tubesheet for the Salem Unit 2 Westinghouse Series 51 Steam Generators.       LCR S05-07 is supported by, but not limited to, the guidance provided in WCAP-14797, Revision 2, "Generic W* Tube Plugging Criteria for 51 Series Steam Generator Tubesheet Region WEXTEX Expansions" and supporting information provided from Westinghouse Letter Report LTR-CDME-05-30, "W* Integrity Evaluation for Salem Unit 2 Limited SG Tube RPC Examination (Based on WCAP-14797, Revision 2).       In accordance with LCR S05-07, the W* Length is the undegraded length of tubing into the tubesheet below the bottom of the WEXTEX transition (BWT) that precludes tube pullout in the event of a complete circumferential separation of the tube below the W* Length.          For the hot leg, the W* Length is 7.0 inches, which represents the most conservative hot leg length defined in WCAP-14797, Revision 2.       The W* Distance is the larger of the following two distances as measured from the top-of-the-tubesheet (TTS): (a) 8-inches below the TTS or (b) the non-degraded distance from the TTS to the bottom of the W*
Length, including the distance from the TTS to the bottom of the WEXTEX transition (BWT) and Non-Destructive Examination (NDE) measurement uncertainties (i.e.,          W*
Distance = W* Length + distance to BWT + NDE uncertainties).          Non-Destructive Examination determines the distance to the BWT for each tube.           The nondestructive examination (NDE) measurement uncertainty is provided from LCR S05-07, as supported by WCAP-14797 Revision 2.       Tubes with indications detected within the W* Distance will be removed from service by tube plugging.
SALEM - UNIT 2                           B 3/4 4-3c                        Amendment No. 262 (PSEG Issued)

REACTOR COOLANT SYSTEM BASES Tube degradation of any type or extent below the W* Distance, including a complete circumferential separation of the tube, is acceptable and therefore may remain in service. As applied at Salem Unit 2, LCR S05-07 is used to define the required tube inspection depth into the tubesheet, and is not used to permit degradation in the W* Distance to remain in service.              Furthermore, potential primary to secondary leakage in the W* Distance, and below the W* Distance, can be conservatively evaluated in accordance with LCR SOS-07.              The leak rate potential for axial, circumferential, and volumetric indications detected within 12 inches from the top of the tubesheet can be conservatively calculated using the constrained crack model as delineated in LCR S05-07 (supported by Westinghouse LTR-CDME-05-30).
The postulated leakage during a steam line break shall be equal                 to the following equation, as supported by LCR S05-07:
Postulated SLB Leakage      =       Assumed Leakage 0-      <TTS + Assumed Leakage       8"-12" <TTS +
Assumed Leakage    >12- <TS Where:        Assumed Leakage 0--8"  <TTS  is    the postulated leakage for indications              that are deemed via flaw depth estimation techniques to be 100% throughwall, and therefore present a potential leak path.             This term is      applicable to detected indications during an in-service inspection and potentially undetected indications in        the steam generator tubes left         in   service between 0 inches and 8 inches below the top of the tubesheet                     (TTS).
Since tubes with indications detected between 0 and 8 inches below the TTS are plugged upon detection,           the calculation    of this    term for the assessment of SLB leakage for the subsequent operation                 cycle following an in-service inspection only requires            consideration     of potentially undetected indications.          The calculation of this term for the assessment of SLB leakage         for the previous operation cycle,           following an in-service inspection,         requires   consideration of both detected and potentially undetected indications.
Assumed Leakage 12-  <TTS  is    the conservatively projected leakage in steam generator tubes between 8 and 12 inches below the top of the tubesheet. Implementation       of LCR S05-07 does not require tube inspection below the W* Distance,           therefore the methodology for conservatively    calculating the population of indications between                  8 and 12 inches below the TTS is         provided by fitting     a SALEM  -  UNIT 2                           B 3/4 4-3d                              Amendment No. 262 (PSEG Issued)

REACTOR COOLANT   SYSTEM BASES regression   line to the cumulative inspection data        (detected indications)    from all    SGs and projecting the number of indications    (to minus 12 inches below TTS)      using a 95-percent probability prediction bound.         The cumulative indications    from all steam generators are conservatively assumed to occur in           one SG (similar to figure   16 of Westinghouse LTR-CDME-05-30).         The conservative leakage rate for the indications between         8 and 12 inches is    0.0033 gpm multiplied by the number of projected indications          (as discussed in    LCR S05-07 submittals LR-N06-0277 and LR-N06-0338).          The leak rate of indications   detected between 8 and 12 inches are bounded by the projected total    discussed above,     assuming that the inspection     results for detected indications do not contradict the calculated population as described previously.
Assumed Leakage >112 <TS is      the calculated leakage from the steam generator tubes left      in   service below 12 inches from the top of the tubesheet. This is    0.00009 gpm times number of tubes left      in  service in  the steam generator.
Each SG is assessed for Main Steam Line Break (MSLB) leakage individually in accordance with the discussion above, and the SG with the most calculated leakage is conservatively assigned as the affected SG.
The calculated MSLB leakage provided above, including MSLB leakage from ali             other sources, shall be reported to the NRC in accordance with applicable Technical Specifications.      The Calculated MSLB Leakage must be less than the maximum allowable MSLB leak rate limit in any one steam generator in order to maintain doses within 10 CFR 50.67 guideline values and within GDC-19 values during a postulated main steam line break event.
SALEM -  UNIT 2                            B 3/4 4-3e                       Amendment No. 262 (PSEG Issued)

REACTOR COOLANT SYSTEM BASES 3/4.4.7    REACTOR COOLANT SYSTEM LEAKAGE 3/4.4.7.1    LEAKAGE DETECTION SYSTEMS The RCS leakage detection systems required by this specification are provided to monitor and detect leakage from the Reactor Coolant Pressure Boundary.           These detection systems are consistent with the recommendations of Regulatory Guide 1.45, "Reactor Coolant Pressure Boundary Leakage Detection Systems," May 1973.
3/4.4.7.2    OPERATIONAL LEAKAGE Industry experience has shown that while a limited amount of leakage is expected from the RCS, the unidentified portion of this leakage can be reduced to a threshold value of less than 1 GPM.       This threshold value is sufficiently      low to ensure early detection of additional leakage.
The 10 GPM IDENTIFIED LEAKAGE limitation provides allowance for a limited amount of leakage from known sources whose presence will not interfere with the detection of UNIDENTIFIED LEAKAGE by the leakage detection systems.
The surveillance requirements for 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 IDENTIFIED LEAKAGE and will be considered as a portion of the allowed limit.
PRESSURE BOUNDARY LEAKAGE of any magnitude is unacceptable since it may be indicative of an impending gross failure of the pressure boundary.
Therefore, the presence of any PRESSURE BOUNDARY LEAKAGE requires the unit to be promptly placed in COLD SHUTDOWN.
Primary to Secondary Leakage Through Any One SG The primary-to-secondary leakage rate limit applies to leakage through any one Steam Generator. The limit of 150 gallons per day per steam generator is based on the operational leakage performance criterion in NEI 97-06, Steam Generator Program Guidelines. The Steam Generator Program operational leakage performance criterion in NEI 97-06 states, "The RCS operational primary-to-secondary leakage through any one SG shall be limited to 150 gallons per day." The limit       is based on operating experience with steam generator tube degradation mechanisms that result in tube leakage. The operational leakage rate criterion in conjunction with the implementation of the Steam Generator Program is an effective measure for minimizing the frequency of steam generator tube ruptures.         The dosage contribution from the tube leakage will be within 10 CFR 50.67 limits in the event of either a steam generator tube rupture or steam line break.       The analyses are based on the total   primary to secondary leakage from all SGs of 1 gallon per minute as a result of accident induced conditions.
SALEM - UNIT 2                         B 3/4 4-4                          Amendment No. 262 (PSEG Issued)

REACTOR COOLANT SYSTEM BASES 3/4.4.7.2 OPERATIONAL LEAKAGE (Continued)
Actions Unidentified leakage or identified leakage in excess of the LCO limits must be reduced to within limits within 4 hours. This action time allows time to verify leakage rates and either identify unidentified leakage or reduce leakage to within limits before the reactor must be shut down.
This action is necessary to prevent further deterioration of the reactor coolant pressure boundary (RCPB). If any pressure boundary leakage exists, or primary-to-secondary leakage is not within limit, or if unidentified or identified leakage cannot be reduced to within limits within 4 hours, the reactor must be brought to lower pressure conditions to reduce the severity of the leakage and its potential consequences. It should be noted that leakage past seals and gaskets is not pressure boundary leakage. The reactor must be brought to HOT STANDBY within 6 hours and COLD SHUTDOWN within 36 hours. This action reduces the leakage and also reduces the factors that tend to degrade the pressure boundary. The action times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. In COLD SHUTDOWN, the pressure stresses acting on the RCPB are much lower, and further deterioration is much less likely.
Surveillances Verifying RCS leakage to be within the LCO limits ensures the integrity of the Reactor Coolant Pressure Boundary is maintained. Pressure boundary leakage would at first appear as unidentified leakage and can only be positively identified by inspection. It should be noted that leakage past seals and gaskets is not pressure boundary leakage. Unidentified leakage and identified leakage are determined by performance of an RCS water inventory balance. The RCS water inventory must be met with the reactor at steady state operating conditions. The surveillance is modified by a Note that the surveillance is not required to be performed until 12 hours after establishing steady state operation. The 12 hour allowance provides sufficient time to collect and process all necessary data after stable plant conditions are established. Steady state operation is required to perform a proper inventory balance since calculations during maneuvering are not useful. For RCS operational leakage determination by water inventory balance, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and Reactor Coolant Pump seal injection and return flows. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
Satisfying the primary-to-secondary leakage limit ensures that the operational leakage performance criterion in the Steam Generator Program is met. If SR 4.4.7.2.1 .c is not met, compliance with LCO 3.4.6, "Steam Generator Tube Integrity," should be evaluated. The 150 gallons per day limit is measured at room temperature (in accordance with EPRI PWR Primary-to-Secondary Leak Guidelines). If it is not practical to assign the leakage to an individual steam generator, all the primary-to-secondary leakage should be conservatively assumed to be from one Steam Generator. The Surveillance is modified by a Note that states that the surveillance is not required to be performed until 12 hours after establishment of steady state operation. For RCS primary-to-secondary leakage determination, steady SALEM - UNIT 2                                    B 3/4 4-4a                    Amendment No. 282 (PSEG Issued)

REACTOR COOLANT SYSTEM BASES 3/4.4.7.2 OPERATIONAL LEAKAGE (Continued) state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and Reactor Coolant Pump seal injection and return flows.
The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program. The primary-to-secondary leakage is determined using continuous process radiation monitors or radiochemical grab sampling (in accordance with EPRI PWR Primary-to-Secondary Leak Guidelines).
3/4.4.8 THIS SECTION DELETED SALEM - UNIT 2                               B 3/4 4-5                     Amendment No. 282 (PSEG Issued)

REACTOR COOLANT SYSTEM BASES 3/4.4.9   SPECIFIC ACTIVITY The limitations on the specific activity of the primary coolant ensure that the resulting 2 hour doses at the site boundary will not exceed an appropriately small fraction of Part 100 limits following a steam generator tube rupture accident in conjunction with an assumed steady state primary-to-secondary steam generator leakage rate of 1.0 GPM. 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 of the Salem site, such as site boundary location and meteorological conditions, were not considered in this evaluation. The NRC is finalizing site specific criteria which will be used as the basis for the reevaluation of the specific activity limits of this site. This reevaluation may result in higher limits.
Reducing T avg to less than 500&deg;F prevents the release of activity should a steam generator tube rupture occur since the saturation pressure of the primary coolant is below the lift   pressure of the atmospheric steam relief valves. The surveillance requirements provide adequate assurance that excessive specific activity levels in the primary coolant will be detected in sufficient time to take corrective action. Information obtained on iodine spiking will be used to assess the parameters associated with spiking phenomena. A reduction in frequency of isotopic analyses following power changes may be permissible if justified by the data obtained.
LCO 3.0.4.c is applicable. This allowance permits entry into the applicable MODE(S) while relying on the ACTIONS.
SALEM - UNIT 2                        B 3/4 4-6                     Amendment No. 258

REACTOR COOLANT SYSTEM BASES 3/4.4.10    PRESSURE/TEMPERATURE    LIMITS The temperature and pressure changes during heatup and cooldown are limited to be consistent with the requirements given in the ASME Boiler and Pressure Vessel Code, Section XI, Appendix G.
: 1)     The reactor coolant temperature and pressure and system heatup and cooldown rate (with the exception of the pressurizer) shall be limited in accordance with Figures 3.4-2 and 3.4-3 for the service period specified thereon.
a)       Allowable combinations of pressure and temperature for specific temperature change rates are below and to the right of the limit lines shown. Limit lines for cooldown rates between those presented may be obtained by interpolation.
b)       Figures 3.4-2 and 3.4-3 define limits to assure prevention of nonductile failure only. For normal operation, other inherent plant characteristics, e.g., pump heat addition and pressurizer heater capacity, may limit the heatup and cooldown rates that can be achieved over certain pressure-temperature ranges.
: 2)     These limit lines shall be calculated periodically using methods provided below.
: 3)     The secondary side of the steam generator must not be pressurized above 200 psig if the temperature of the steam generator is below 70*F.
: 4)     The pressurizer heatup and cooldown rates shall not exceed 100 0 F/hr and 200&deg;F/hr, respectively. The spray shall not be used if the temperature difference between the pressurizer and the spray fluid is greater than 320 0F.
: 5)     System preservice hydrotests and in-service leak and hydrotests shall be performed at pressures in accordance with the requirements of ASME Boiler and Pressure Vessel Code, Section XI.
The fracture toughness properties of the ferritic materials in the reactor vessel are determined in accordance with the NRC Standard Review Plan, ASTM E185-82, and in accordance with additional reactor vessel requirements. These properties are then evaluated in accordance with Appendix G of the 1996 Summer Addenda to Section XI of the ASME Boiler and Pressure Vessel Code and the calculation methods described in WCAP-14040-NP-A, Rev. 2, "Methodology Used to Develop Cold Overpressure Mitigating System Setpoints and RCS Heatup and Cooldown Limit Curves", January 1996, and ASME Boiler and Pressure Vessel Code Case N-640, "Alternative Reference Fracture Toughness for Development of P-T Limit Curves for Section XI, Division 1", approved March 1999.
Heatup and cooldown limit curves are calculated using the most limiting value of the nil-ductility reference temperature, RT",       at the end of 32 effective full power years of service life.       The 32 EFPY service life period is chosen such that the limiting RTNDT at the 1/4T location in the core region is greater than the RTNT of the limiting unirradiated material.      The selection of such a limiting RTH* assures that all components in the Reactor Coolant System will be operated conservatively in accordance with applicable Code requirements.
SALEM - UNIT 2                    B 3/4 4-7                      Amendment No. 224

REACTOR COOLANT SYSTEM BASES The reactor vessel materials have been tested to determine their initial           RT,*;
the results of these tests are shown in Table B 3/4.4-1.          Reactor operation and resultant fast neutron (E greater than 1 MEV) irradiation can cause an increase in the RTmn. An adjusted reference temperature, (ART), based upon the fluence and the copper and nickel content of the material in question, can be predicted.
The ART is based upon the largest value of RTND       computed by the methodology presented in Regulatory Guide 1.99, Revision 2.       The ART for each material is given by the following expression:
ART  = Initial     RTND + ARTNT + Margin Initial RTHI. is the reference temperature for the unirradiated material.
ARTDT is   the mean value of the adjustment in reference temperature caused by the irradiation and is calculated as follows:
ARTND    = Chemistry Factor x Fluence Factor The Chemistry Factor, CF (F), is a function of copper and nickel content.           It is given in Table B3/4.4-2 for welds and in Table B3/4.4-3 for base metal (plates and forgings). Linear interpolation is permitted.
The predicted neutron fluence as a function of Effective Full Power Years (EFPY) has been calculated and is shown in Figure B3/4.4-1. The fluence factor can be calculated by using Figure B3/4.4-2. Also, the neutron fluence at any depth in the vessel wall is determined as follows:
f  =    (f surface) x (e-0.24X where "f surface" is. from Figure B3/4.4-1,      and X (in   inches)  is the depth into the vessel wall.
Finally, the "Margin" is the quantity in *F that is to be added to obtain conservative, upper-bound values of adjusted reference temperature for the calculations required by Appendix G to 10 CFR 50.
Margin = 240i2 + (,2 If a measured value of initial       RTN* for the material in question is used,
* may be taken as zero. If generic value of initial       RTf0i is used, a, should be obtained from the same set of data. The standard deviations, for ART,*,
aA, are 28OF for welds and 17*F for base metal, except that aA need not exceed 0.50 times the mean value of ARTND. surface.
The heatup and cooldown limit curves of Figures 3.4-2 and 3.4-3 include predicted adjustments for this shift in RTNDT at the end of 32 EFPY.
SALEM - UNIT 2                            B 3/4 4-8                  Amendment No. 224

REACTOR COOLANT SYSTEM BASES Values of ARTNDT determined in this manner may be used until the results from the material surveillance program, evaluated according to ASTM E185, are available. Capsules will be removed in accordance with the requirements of ASTM E185-82 and 10 CFR Part 50, Appendix H. The heatup and cooldown curves must be recalculated when the ARTND determined from the surveillance capsule exceeds the calculated ARTNDT for the equivalent capsule radiation exposure.
Allowable pressure-temperature relationships for various heatup and cooldown rates are calculated using methods derived from Appendix G in Section XI of the ASME Boiler and Pressure Vessel Code as required by Appendix G to 10 CFR Part 50 and these methods are discussed in detail in WCAP-14040-NP-A, Rev. 2, "Methodology Used to Develop Cold Overpressure Mitigating System Setpoints and RCS Heatup and Cooldown Limit Curves", January 1996, and ASME Boiler and Pressure Vessel Code Case N-640, "Alternative Reference Fracture Toughness for Development of P-T Limit Curves for Section XI, Division I", approved March 1999.
The general method for calculating heatup and cooldown limit curves is based upon the principles of the linear elastic fracture mechanics (LEFM) technology. In the calculation procedures a semi-elliptical surface defect with a depth of one-quarter of the wall thickness, T, and a length of 3/2T is assumed to exist at the inside of the vessel wall as well as at the outside of the vessel wall. The dimensions of this postulated crack, referred to in Appendix G of ASME Section XI as the reference flaw, amply exceed the current capabilities of inservice inspection techniques. Therefore, the reactor operation limit curves developed for this reference crack are conservative and provide sufficient safety margins for protection against nonductile failure.
To assure that the radiation embrittlement effects are accounted for in the calculation of the limit curves, the most limiting value of the nil-ductility reference temperature, RTR*, is used and this includes the radiation induced shift, ARTN* corresponding to the end of the period for which heatup and cooldown curves are generated.
The ASME approach for calculating the allowable limit curves for various heatup and cooldown rates specifies that the total stress intensity factor, KI, for the combined thermal and pressure stresses at any time during heatup or cooldown cannot be greater than the reference stress intensity factor, Kic, for the metal temperature at that time. KIc is obtained from the reference fracture toughness curve, defined in ASME Code Case N-640. The Krc curve is given by the equation:
KIc = 33.2 + 20.734 exp (0.02(T-RTm)J      (1) where Kzc is the reference stress intensity factor as a function of the metal temperature T and the metal nil-ductility reference temperature RTrDT. Thus, the governing equation for the heatup-cooldown analysis is defined in Appendix G of the ASME Code as follows:
C KIm + KIT : KSc                          (2)
SALEM - UNIT 2                        B 3/4 4-9               Amendment No. 224

REACTOR COOLANT SYSTEM BASES where KIN is  the stress intensity factor caused by membrane  (pressure) stress.
KIT is the stress intensity factor caused by the thermal gradients.
KIc is provided by the code as a function of temperature relative to the RTNDT of the material.
C = 2.0 for level A and B service limits, and C = 1.5 for inservice hydrostatic and leak test operations.
At any time during the heatup or cooldown transient, Kzc is determined by the metal temperature at the tip of the postulated flaw, the appropriate value for RTNDT, and the reference fracture toughness curve. The thermal stresses resulting from temperature gradients through the vessel wall are calculated and then the corresponding (thermal) stress intensity factors, KIT, for the reference flaw are computed. From Equation (2) the pressure stress intensity factors are obtained and from these the allowable pressures are calculated.
COOLDOWN For the calculation of the allowable pressure versus coolant temperature during cooldown, the Code reference flaw is assumed to exist at the inside of the vessel wall. During cooldown, the controlling location of the flaw is always at the inside of the wall because the thermal gradients produce tensile stresses at the inside, which increase with increasing cooldown rates.
Allowable pressure-temperature relations are generated for both steady-state and finite cooldown rate situations. From these relations composite limit curves are constructed for each cooldown rate of interest.
The use of the composite curve in the cooldown analysis is necessary because control of the cooldown procedure is based on measurement of reactor coolant temperature, whereas the limiting pressure is actually dependent on the material temperature at the tip of the assumed flaw. During cooldown, the 1/4T vessel location is at a higher temperature than the fluid adjacent to the vessel ID. This condition, of course, is not true for the steady-state situation. It follows that at any given reactor coolant temperature, the AT developed during cooldown results in a higher value of Kxc at the 1/4T location for finite cooldown rates than for steady-state operation.
Furthermore, if conditions exist such that the increase in K1 c exceeds KIT, the calculated allowable pressure during cooldown will be greater than the steady-state value.
The above procedures are needed because there is no direct control on temperature at the 1/4T location, therefore, allowable pressures may unknowingly be violated if the rate of cooling is decreased at various intervals along a cooldown ramp. The use of the composite curve eliminates this problem and assures conservative operation of the system for the entire cooldown period.
SALEM - UNIT 2                        B 3/4 4-10              Amendment No. 224

REACTOR COOLANT SYSTEM BASES HEATUP Three separate calculations are required to determine the limit curves for finite   heatup rates. As is done in the cooldown analysis, allowable pressure-temperature relationships are developed for steady-state conditions as well as finite heatup rate conditions assuming the presence of a 1/4T defect at the inside of the vessel wall. The thermal gradients during heatup produce compressive stress at the inside of the wall that alleviate the tensile stresses produced by internal pressure. The metal temperature at the crack tip lags the coolant temperature. Therefore, the Kic for the 1/4T crack during heatup is lower than the Kjc for the 1/4T crack during steady-state conditions at the same coolant temperature. During heatup, especially at the I
end of the transient, conditions may exist such that the effects of compressive thermal stresses and different Kics for steady-state and finite heatup rates do not offset each other and the pressure-temperature curve based on steady-state conditions no longer represents a lower bound of all similar curves for finite heatup rates when the 1/4T flaw is considered. Therefore, both cases have to be analyzed in order to assure that at any coolant temperature the lower value of the allowable pressure calculated for steady-state and finite heatup rates is obtained.
The second portion of the heatup analysis concerns the calculation of pressure-temperature limitations for the case in which a 1/4T deep outside surface flaw is assumed. Unlike the situation at the vessel inside surface, the thermal gradients established at the outside surface during heatup produce stresses which are tensile in nature and thus tend to reinforce any pressure stresses present. These thermal stresses, of course, are dependent on both the rate of heatup and the time (or coolant temperature) along the heatup ramp. Furthermore, since the thermal stresses, at the outside are tensile and increase with increasing heatup rate, a lower bound curve cannot be defined.
Rather, each heatup rate of interest must be analyzed on an individual basis.
Following the generation of pressure-temperature curves for both the steady-state and finite heatup rate situations, the final limit curves are produced as follows. A composite curve is constructed based on a point-by-point comparison of the steady-state and finite heatup rate data.      At any given temperature, the allowable pressure is taken to be the lesser of the three values taken from the curves under consideration.
The use of the composite curve is necessary to set conservative heatup limitations because it is possible for conditions to exist such that over the course of the heatup ramp the controlling condition switches from the inside to the outside and the pressure limit must at all times be based on analysis of the most critical criterion.
SALEM  -  UNIT  2                     B 3/4 4-11                Amendment No. 224

Finally, the new 10CFR50 rule which addresses the metal temperature of the closure head flange regions is considered. This 10CFR50 rule states that the metal temperature of the closure flange regions must exceed the material RTNDT by at least 120OF for normal operation when the pressure exceeds 20 percent of the preservice hydrostatic test pressure (621 psig for Salem). Table B3/4-.4-1 indicates that the limiting RTNDT of 28OF occurs in the closure head flange of Salem Unit 2, and the minimum allowable temperature of this region is   148*F at pressures greater than 621 psig. These limits do not affect Figures 3.4-2 and 3.4-3.
Although the pressurizer operates in temperature ranges above those for which there is reason for concern of non-ductile failure, operating limits are provided to assure compatibility of operation with the fatigue analysis performed in accordance with the ASME Code requirements.
The OPERABILITY of two POPSs or an RCS vent opening of greater than 3.14 square inches ensures that the RCS will be protected from pressure transients which could exceed the limits of Appendix G to 10 CFR Part 50 when one or more of the RCS cold legs are less than or equal to 312 0 F. Either POPS has adequate relieving capability to protect the RCS from overpressurization when the transient is limited to either (1) the start of an idle RCP with the secondary water temperature of the steam generator less than or equal to 50OF above the RCS cold leg temperatures, or (2) the start of an Intermediate Head Safety Injection pump and its injection into a water solid RCS, or the start of a High Head Safety Injection pump in conjunction with a running Positive Displacement pump and its injection into a water solid RCS. The minimum electrical power sources required to assure POPS operability (based on POPS meeting the single failure criteria) consist of a.normal (via offsite power) and an emergency (via batteries) power source for each train of POPS. Emergency diesel generators are not required for POPS to meet single failure criteria and therefore are not required for POPS OPERABILITY.
LCO 3.0.4.b is not applicable to an inoperable LTOP system when entering MODE 4.
There is an increased risk associated with entering MODE 4 from MODE 5 with an inoperable LTOP system. The provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.
SALEM - UNIT 2                        B 3/4 4-12                    Amendment No. 258

TABLE     3/4.4-1 SALEM UNIT   2 REACT(       ESSEL TOUGHNESS    DATA Average Upper Shell Energy Component     Plate No. Material    Cu (%)      Ni      T     50 ft-lb  RT (OF)       Normal to          Principal or Weld      Type                  (%)   (*F)    35 - Mil            Principal Working       Working No.                                             Temp                  Direction          Direction (OF)                  (ft-lb)            (ft-lb)
Closure Hd Dome     B4709      A533BCLI       0.11     0.70   -40        45'*     -15*           82.5                127 Closure Hd Peel     B5007-3    A533BCLl       0.12     0.57   -20        15"      -20*            97'                149 Closure Hd Peel     B4707-1    A533BCL1       0.10     0.55     0        51'        0*            84*                129 Closure Hd Peel     B4707-3    A533BCL1       0.13     0.63     0        66*        6*            84*              129.5 Closure Hd Flng     B4702-1    AS08CL2          -      0.68   28*        39*       28*           104'                160 Vessel Flange       B5001      A508CL2          -      0.70   12'         4*       12'           107"                164 Inlet Nozzle        84703-1    A508CL2          -      0.69   60*        62*       60*           >72*     "111"*
Inlet Nozzle        B4703-2    A508CL2          -      0.69   60*        25*       60*           >61*               >94"*
Inlet Nozzle        84703-3    A5S08CL2         -      0.68   60*        32*       60*           >71    -          >109**
Inlet Nozzle        B4703-4    A508CL2          -      0.81   60*        40*       60*            80*              123.5 Outlet Nozzle       B4704-1    A508CL2          -      0.84   60*         8*       60*            82*                126 Outlet Nozzle       B4704-2    A508CL2          -      0.77   60*        20*       60*            75*                116 Outlet Nozzle       B4704-3    A508CL2          -      0.69   28*         8*       28*            82*                126 Outlet Nozzle       B4704-4    A508CL2          -      0.71   60*        40*       60*            77*                119 Upper Shell         84711-1    A533BCL1       0.11     0.55    0*        50*        0'            87*                134 Upper Shell         B4711-2    A533BCL1       0.14     0.56   -10        60*        0*            79*                122 Upper Shell         B4711-3    A533BCL1       0.12     0.58   -10        88*       28'            69*                107 Inter. Shell        84712-1    A533BCL1       0.13     0.56     0                    0            106 I
                                                                         <60                                         138 Inter. Shell        B4712-2    A533BCLI       0.12     0:62   -20         72        12             97              127.5 Inter. Shell        B4712-3    A533BCLI       0.11     0.57   -50         70        10            107                116 Lower Shell         B4713-1    A533BCL1       0.12     0.60   -10         68         8             98                127 Lower Shell         B4713-2    A533BCL1       0.12     0.57   -20         68         8            103              135.5 Lower Shell         B4713-3    A533BCLI       0.12     0.58   -10         70        10            121              135.5 Bottom Hd Peel      B4709-1    A533BCLI       0.12     0.60   -30        54*       -6'            90*                139 Bottom Hd Peel      B4709-2    A533BCLI       0.12     0.58   -20        42*      -18'            89*              137.5 Bottom Hd Peel      B4709-3    A533BCLI       0.11     0.56   -20        71'       11'            93'                143 Bottom Head         B4710      A533BCL1       0.12     0.60   -30        60*        0*            77*                118 Circum. Weld Bet    8-442                     0.28     0.74     -          -    -56 Nozzle Shell &
Int. Shell Circum. Weld Bet   9-442                    0.197    0.060     -                -56***          99.7 Int. Shell & Lower Shell Int. Shell          2-442           -        0.219    0.735     -                -56***          96.2 Vertical Weld       [A,B,C]
Lower Shell         3-442                    0.213    0.867                                       114 Vertical Weld       [A, B,C]
Estimated per NRC Standard Review Plan Section 5.8.2.
'*     100% Shear not reached
**'    Estimate per Pressurized Thermal Shock Rule, 10 CFR 50.61 I
SALEM -   UNIT 2                                         B 3/4 4-13                                      Amendment No. 224

TABLE a 3/4.4.2 insT          WnCT   M0 MM a o
       ,       L &#xa3;p1.0 0            20    20      20     30   30     20   20 0.01      .210     20      20    20    20     20   30 0.02         21    26      2?    27           2?   2?
o..m          22           41    41    41     41   41 0.04         24    43      &4    .4    v14    .4 0.06         26    4,      6?                      U 0.06         313           77     82   68    lO8 182 a
0.0?         32            u                       95 0.06         38            95 106 Ila         108  106 0.00         40            94   115   122   122 0.10               To      9?   122   133   135 0.11         40          101    130         148  148 0.12         52    72 88    10o    I13   153 105   1et   141 0.13                     106    139         172 AS    711                162        170 0.14                     100    142         182 61    72 84 0.15               76    112          175 144   191 0.16         70     a    115    149   178     in 211 0.17         75          119    151              221 0.18.        7,   100    122    IS4   187   214  230 0.19         53          126    157   191   220  238 104            I"?   =168 0.20         as          129    160   194   223  245 0.21         92  112     133          197   229  252 0.22         '7          137    1847             257 0.23       101   117     140          203   232 121     144                     263 0.24       106                  173         239  268 203 0.25       110           145    175 is                  130         243  272 0.26       113   134     151          212   246  276 0.2?       119   138            134   216   249 0.28       122   .121    150    137         251 184          213        254 0.20       128   112            191         254  267 I"?
0.20       131   114     167    194 225     257  290 0.31                                        260  293 0.32       140           172 176    202 231L        296 0.33       I"     190      8oo  130 234     268 0.34       149    134 147            2W9238      269  202 101 0.35       153    172           212   241   272  205 0.36       I15    130 I"5     191   216   24    275  206 0.37                      196.              278  311 0.38              lg     MO     223   250   281  314 0.39       171           203    227   254   26S  317 0.40       176           207    231   257   288  320 SALEK UNIT Z            S 3/4   4-14        Amendment No. 86

TABLE B 3/4.4-3 CSThT FACMTU PU UA.       MAL, "1 0         210   20     gc   O go0   2    20    2 0.01      20     20    20    20    20   20    20 0.02      20     20    20    20    20   20    20 0.03      20     20    20    20    20   20    20 0.04     22     26    26    26    26   26    26 0.09      2 321        31    31    31   31   31 0.06      29     37    37    27    27  -37   27 0.07      31     43    44    44    44   44   44 0.01      34     48    81    61    61   61   51 0.09      37     53          5     58 SO   56   &8 0.10      41     U8     68   8U    67   67   67 0.11      45     62    72    74    77   77    77 0.12      49     87    79    53    If   U    86 0.13      53     71    U     91         96 N6   96 0.14      57     75    91   100   106  106  106 0.15      61     s0    9    110   116  117  117 0.16      6      84   104   111   123  125  125 0.17      69     IS   110   127   132  135  133 0.13      73     92   115   134   141  144  144
: 0. 19     78     87   120   142   15O  154  154 0.20      32   102    123   149   159  164  16 0.21      U8   107    129   158   167  172  174 0.22      91   112    134   161   175  181  184 0.23      U6   117    138   167   184  190  194 0.24     100   121    143   172   191  199  204 0.25     104   126    141   176   19"  20   214 0.26     106   130    151   180   206  216  221 0.27     114   134    155   154   211    5  230 0.28     119   138    160   187   216 233   239 0.29     124   142    164   191   221  241  248 0.30     129   145    167   194   225  240  267 0.31     134   151    172   198   228 2U    265 0.32     139   155    175   202   231  260  274 0.33     144   160    10     go   234  264  232 0.34     149   164    184    09   238   M8  290 0.25     153   114    187   212   241 272   298 0.3O     15    173    111   216   24   27$  303 0.37     152   177    19i   220   24   278  30 0.38     166   1832   10    223   250  261  313 0.39     171   1 IM      0    227   264  28   317 0.40     175   1in    207   231   257  28   320 SALE.M UNIT   2              B 3/4. 4-15        Amendment No. S6

I .OE+20 1.OE+19 E
&#xfd;9 U-0 z
1.OE+18 1.OE-417 0    5        10         15         20        25       30       35 Service Life (Effective Full Power Years)
Figure B 3/4.4-1 Fast neutron fluence (E > 1 MeV)       as a function of full power service life (EFPY)
SALEM - UNIT 2                        B 3/4 4-16                  Amendment No. 224

C
  -1 I
a                     IN      1111111IIII IIII 11111il0:111          i mill IIt 1111 111M.'I '.'1111&#xfd;ilid               fill a            HM i&#xfd;it &#xfd;dl           I I 1111111 W) 111&#xfd;!INN I I 1W1&#xfd;1i,    1111 11111111111111h 0 111 11 w-I ru We, an                                 slow M
 'I CL CD Fluence Factor for use in       the expression for ARTNDT 03 (rO FIGURE a 3/4.4-2.
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C0

REACTOR COOLANT SYSTEM BASES 3/4.4.11 DELETED 3/4.4.12 REACTOR VESSEL HEAD VENTS Reactor Coolant System vents are provided to exhaust noncondensible gases and/or steam from the Reactor Coolant System that could inhibit natural circulation core cooling. The OPERABILITY of a reactor vessel head vent path ensures the capability exists to perform this function.
The valve redundancy of the Reactor Coolant System vent paths serves to minimize the probability of inadvertent or irreversible actuation while ensuring that a single failure vent in a valve power supply or control system does not prevent isolation of the vent path.
The function, capabilities, and testing requirements of the Reactor Coolant System Vent Systems are consistent with the requirements of Item ll.B.1 of NUREG-0737, "Clarification of TMI Action Plant Requirements," November 1980. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
SALEM - UNIT 2                                B 3/4 4-18                         Amendment No.282 (PSEG Issued)

3/4.5   EMERGENCY CORE COOLING SYSTEMS BASES 3/4.5.1   ACCUMULATORS The OPERABILITY of each RCS accumulator ensures that a sufficient volume of borated water will be immediately forced into the reactor core through each of the cold legs in the event the RCS pressure falls below the pressure of the accumulators. This initial    surge of water into the core provides the initial cooling mechanism during large RCS pipe ruptures.
The limits on accumulator volume, boron concentration and pressure ensure that the assumptions used for accumulator injection in the safety analysis are met.
The accumulator power operated isolation valves are considered to be "operating bypasses" in the context of IEEE Std 279-1971, which requires that bypasses of a protective function be removed automatically whenever permissive conditions are not met.      In addition, as these accumulator isolation valves fail to meet single failure criteria, removal of power to the valves is required.
The limits for operation with an accumulator inoperable for any reason except an isolation valve closed minimizes the time exposure of the plant to a LOCA event occurring concurrent with failure of an additional accumulator which may result in unacceptable peak cladding temperatures.      If a closed isolation valve cannot be immediately opened, the full capability of one accumulator is not available and prompt action is required to place the reactor in a mode where this capability is not required.
3/4.5.2 and 3/4.5.3    ECCS SUBSYSTEMS The OPERABILITY of two independent ECCS subsystems ensures that sufficient emergency core cooling capability will be available in the event of a LOCA assuming the loss of one subsystem through any single failure consideration.
Either subsystem operating in conjunction with the accumulators is capable of supplying sufficient core cooling to limit the peak cladding temperatures within acceptable limits for all postulated break sizes ranging from the double ended break of the largest RCS cold leg pipe downward.      In addition, each ECCS subsystem provides long term core cooling capability in the recirculation mode during the accident recovery period.
SALEM -  UNIT 2                         B 3/4 5-1

EMERGENCY CORE COOLING SYSTEMS BASES ECCS SUBSYSTEMS   (Continued)
With the RCS temperature below 350'F, one OPERABLE ECCS subsystem is acceptable without single failure consideration on the basis of the stable reactivity condition of the reactor and the limited core cooling requirements.
The limitation for a maximum of one safety injection pump or one centrifugal charging pump to be OPERABLE and the Surveillance requirement to verify all safety injection pumps except the allowed OPERABLE safety injection pump to be inoperable below 312'F provides assurance that a mass addition pressure transient can be relieved by the operation of a single POPS reliefvalve.
When running a safety injection pump with the RCS temperature less than 312 0Flwith the potential for injecting into the RCS and creating a mass addition pressure transient, two independent means of preventing reactor coolant system injection will be utilized. The two independent means can be satisfied by any of the following methods:
(1) A manual isolation valve locked in the closed position; or (2) Two manual isolation valves closed; or (3) One motor operated valve closed and its breaker de-energized and control circuit fuses removed; or (4) One air operated valve closed and its air supply maintained in such a manner as to ensure that the valve will remain closed.
The surveillance requirements, which are provided to ensure the OPERABILITY of each component, ensure that, at a minimum, the assumptions used in the safety analyses are met and that subsystem OPERABILITY is maintained. The safety analyses make the assumptions with respect to:     1) both the maximum and minimum total system resistance, and 2) both the maximum and minimum branch injection line resistance. These resistances, in conjunction with the ranges of potential pump performance, are used to calculate the maximum and minimum ECCS flow assumed in the safety analyses.
The maximum and  minimum flow surveillance requirements in conjunction with the maximum and   minimum pump performance curves ensures that the assumptions of total   system resistance and the distribution of that system resistance:among the   various paths are met.
The maximum total pump flow surveillance requirements ensure the pump runout limits of 560 gpm for the centrifugal charging pumps and 675 gpm for the safety injection pumps are not exceeded. Due to the effect of pump suction boost alignment, the runout limits for the surveillance criteria are : 554 gpm for C/SI pumps,
* 664 gpm for SI pumps in cold leg alignment and
* 654 gpm for SI pumps in hot leg alignment.
The surveillance requirement for the maximum difference between the maximum and minimum individual injection line flows ensure that the minimum individual injection line resistance assumed for the spilling line following a LOCA is met.
LCO 3.0.4.b is not applicable to an inoperable ECCS high head subsystem when entering MODE 4. There is an increased risk associated with entering MODE 4 from MODE 5 with an inoperable ECCS high head subsystem.
The provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and componentsi should not be applied in this circumstance.
SALEM - UNIT 2                        B 3/4 5-2             Amendment No. 258

EMERGENCY CORE COOLING SYSTEMS BASES'.
3/4.5.4. SEAL INJECTION FLOW The Reactor Coolant Pump (RCP) seal injection flow restriction limits the amount of ECCS flow that would-be diverted from the injection path following an ECCS actuation. This limit is based on safety analysis assumptions, since RCP seal injection flow is not isolated during Safety Injection (SI).
The LCO is not strictly a flow limit, but rather a flow limit based on a flow line resistance. Line pressure and flow must be known to establish the proper line resistance. Flow line resistance is determined by assuming that the RCS pressure is at normal operating pressure, and that the centrifugal charging pump discharge pressure is greater than or equal to 2430 psig. Charging pump header pressure is used instead of RCS pressure, since it is more representative of flow diversion during an accident. The additional LCO modifier, charging flow control valve full open, is required since the valve is designed to fail open. With the LCO specified discharge pressure and control valve position, a flow limit is established. This flow limit is used in the accident analysis.
A provision has been added to exempt surveillance requirement 4.0.4 for entry into MODE 3, since the surveillance cannot be performed in a lower mode. The exemption is permitted for up to 4 hours after the RCS pressure has stabilized within
+/- 20 psig of normal operating pressure. The RCS pressure requirement produces the conditions necessary to correctly set the manual throttle valves. The exemption is limit-ed to 4 hours to ensure timely surveillance completion once the necessary conditions are established.
3/4.5.5   REFUELING WATER STORAGE TANK The OPERABILITY of the RWST as a part of the ECCS ensures that a sufficient supply of borated water is available for injection by the ECCS in the event of a LOCA.
The limits on RWST minimum volume and boron concentrations ensure that:     (1) sufficient water is available within containment to permit recirculation cooling flow to the core, (2) the reactor will remain subcritical in the cold condition following a small LOCA assuming complete mixing of the RWST, RCS, and ECCS water volumes with all control rods inserted except the most reactive control assembly (ARI-1), and (3) the reactor will remain subcritical in the cold condition following a large break LOCA,(break flow area > 3.0 sq. ft.) assuming complete mixing of the RWST, RCS, and ECCS water and other sources of water that may eventually reside in the sump following a LOCA with alql control rods assumed to be out (ARO). The limits on contained water volume and boron concentration also ensure a pH value of between 7.0 and 10.0 for the solution recirculated within containment after a LOCA. This pH band minimizes the evolution of iodine and minimizes the effect of chloride and caustic stress corrosion on mechanical systems and components. The contained water volume limit includes an allowance for water not usable because of tank discharge line location or other physical characteristics.
SALEM - UNIT 2.                          B 3/4 5-3                   Amendment No.258

3/4.6 CONTAINMENT SYSTEMS BASES 3/4.6.1 PRIMARY CONTAINMENT 3/4 6.1.1 CONTAINMENT INTEGRITY Primary CONTAINMENT INTEGRITY ensures that the release of radioactive materials from the containment atmosphere will be restricted to those leakage paths and associated leak rates assumed in the accident analyses.       This restriction, in conjunction with the leakage rate limitation, will limit the site boundary radiation doses to within the limits of 10 CFR 100 during accident conditions.
The purpose of this surveillance requirement (4.6.1.1a) is not to perform any testing or valve manipulations, but to verify that containment isolation valves capable of being mispositioned are in their proper safety position (closed).
Physical verification (hands on verification) that these penetrations (containment isolation valves) are in the proper position is performed prior to entering Mode 4 from Mode 5 and documented in the appropriate valve line-up.
Allowing the use of administrative means to verify compliance with the surveillance requirement for these valves is acceptable based on the limited access to these areas in Modes 1, 2, 3, and 4 for ALARA reasons.      Therefore, the probability of misalignment of these containment isolation valves, once they have been verified in the proper position, is small.
The service water accumulator vessel and discharge valves function to maintain water filled, subcooled fluid conditions in the containment fan coil unit (CFCU) cooling loops during accident conditions.       The service water accumulator vessel and discharge valves were installed to address the Generic Letter 96-06 issues of column separation waterhammer and two phase flow during an accident involving a loss of offsite power.       The operability of each service water accumulator vessel and discharge valve is required to ensure the integrity of containment penetrations associated with the containment fan coil units during accident conditions. If a service water accumulator vessel does not meet the vessel surveillance requirements, or if the discharge valve response time does not meet design acceptance criteria when tested in accordance with procedures, the containment integrity requirements of the CFCU cooling loops exclusively supplied by the inoperable accumulator vessel or discharge valve are not met. Limiting Condition for Operation 3.6.1.1 is applicable, and the cooling loops for the two CFCU's exclusively supplied by the inoperable accumulator are to be removed from service and isolated to maintain containment integrity.
3/4 6.1.2 CONTAINMENT LEAKAGE The limitations on containment leakage rates ensure that the total containment leakage volume will not exceed the value assumed in the accident analyses at the peak accident pressure 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 or less than or equal to 0.75 Lt, as applicable, during performance of the periodic test to account for possible degradation of the containment leakage barriers between leakage tests.
The surveillance testing for measuring leakage rates are consistent with the Containment Leakage Rate Testing Program.
3/4.6.1.3 CONTAINMENT AIR LOCKS Containment air locks form part of the containment pressure boundary and provide a means for personnel access during all MODES of operation.
Each air lock is nominally a right circular cylinder, 10 feet in diameter, with a door at each end.      The doors are interlocked during normal operation to prevent simultaneous opening.
SALEM - UNIT 2                   B 3/4 6-1                      Amendment No.208

3/4.6 CONTAINMENT SYSTEMS BASES During periods when containment is not required to be OPERABLE, the door interlock mechanism may be disabled, allowing both doors of an air lock to remain open for extended periods when frequent containment entry is necessary.      Each air lock door has been designed and tested to certify its ability to withstand a pressure in excess of the maximum expected pressure following a Design Basis Accident (DBA) in containment. As such, closure of a single door supports containment OPERABILITY. Each of the doors contains double gasketed seals and local leakage rate testing capability to ensure pressure integrity.      To effect a leak tight seal, the air lock design uses pressure-seated doors (i.e., an increase in containment internal pressure results in increased sealing force on each door).
Each personnel air lock is provided with limit switches on both doors that provide control room indication of door position. Additionally, control room indication is provided to alert the operator whenever an air lock door interlock mechanism is defeated.
The containment air locks form part of the containment pressure boundary.
As such, air lock integrity and leak tightness is essential for maintaining the containment leakage rate within limit in the event of a DBA. Not maintaining air lock integrity or leak tightness may result in a leakage rate in excess of that assumed in the unit safety analysis.
The DBAs that result in a release of radioactive material within containment are a loss of coolant accident and a rod ejection accident.      In the analysis of each of these accidents, it is assumed that containment is OPERABLE such that release of fission products to the environment is controlled by the rate of containment leakage. The containment was designed with an allowable leakage rate of 0.1% of containment air weight per day. This leakage rate is defined in 10CFR50, Appendix J as La = 0.1% of containment air weight per day, the maximum allowable containment leakage rate at the calculated peak 6
containment internal pressure P, = 47.0 psig following a DBA. The allowable leakage rate forms the basis for the acceptance criteria imposed on the surveillance requirements associated with the air locks.
Each containment air lock forms part of the containment pressure boundary.
As part of containment, the air lock safety function is related to control of the containment leakage rate resulting from a DBA. Thus, each air lock's structural integrity and leak tightness are essential to the successful mitigation of such an event.
Each air lock is required to be OPERABLE. For the air lock to be considered OPERABLE, the air lock interlock mechanism must be OPERABLE, the air lock must be in compliance with the Type B air lock leakage test, and both air lock doors must be OPERABLE. The interlock allows only one air lock door of an air-,lock to be opened at one time. This provision ensures that a gross breach of containment does not exist when containment is required to be OPERABLE.
Closure of a single door in each air lock is sufficient to provide a leak tight barrier following postulated events. Nevertheless, both doors are kept closed when the air lock is not being used for normal entry into and exit from containment.
In MODES 1, 2, 3, and 4, a DBA could cause a release of radioactive material to containment. In MODES 5 and 6, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, the containment air locks are not required in MODE 5 to prevent leakage of radioactive material from containment. The requirements for the containment air locks during MODE 6 are addressed in LCO 3.9.4, "Containment Building Penetrations".                                                               6 SALEM - UNIT 2                  B 3/4 6-1a                     Amendment No.208

3/4.6 CONTAINMENT   SYSTEMS BASES The ACTIONS are modified by five notes. Note (1) allows entry and exit to perform repairs on the affected air lock component. If the outer door is inoperable, then it may be easily accessed for mott repairs.      It is preferred that the air lock be accessed from inside primary containment by entering through the other OPERABLE air lock. However, if this is not practicable, or if repairs on either door must be performed from the barrel side of the door then it is permissible to enter the air lock through the OPERABLE door, which means there is a short time during which the containment boundary is not intact (during access through the OPERABLE door). The ability to open the OPERABLE door, even if it means the containment boundary is temporarily not intact, is acceptable due to the low probability of an event that could pressurize the containment during the short time in which the OPERABLE door isexpected to be open. After each entry and exit, the OPERABLE door must be immediately closed.
If ALARA conditions permit, entry and exit should be via an OPERABLE air lock.
Note (2) adds clarification that separate condition entry is allowed for each air lock. This is acceptable, since the required ACTIONS provide appropriate compensatory measures for each inoperable air lock.      Complying with the Required Actions may allow for continued operation.      A subsequent inoperable air lock is governed by condition entry for that air lock.
Notes (3) and (4) ensure that only the required ACTIONS and associated completion times of condition c. are required if both doors in the same air lock are inoperable. With both doors in the same air lock inoperable, an OPERABLE door is not available to be closed. Required ACTIONS c.l and c.2 are the appropriate remedial actions. The exception of these Notes does not affect tracking the completion time from the initial   entry into condition a., only the requirement to comply with the required ACTIONS.
In the event the air lock leakage results in exceeding the overall containment leakage rate, Note (5) directs entry into the applicable Conditions and required ACTIONS of LCO 3.6.1, "Primary Containment".
With one air lock door in one or more containment air locks inoperable, the OPERABLE door must be verified closed (ACTION a.l) in each affected containment air lock. This ensures that a leak tight containment barrier is maintained by the use of an OPERABLE air lock door. This ACTION must be completed within 1 hour. The specified time period is consistent with the ACTIONS of LCO 3.6.1.1 that requires that containment be restored to OPERABLE status within 1 hour. OPERABILITY of the air lock interlock is not required to support the OPERABILITY of an air lock door.
In addition, the affected air lock penetration must be isolated by locking closed the OPERABLE air lock door within the 24 hour completion time (ACTION a.2). The 24 hour completion time is reasonable for locking the OPERABLE air lock door, considering the OPERABLE door of the affected air lock is being maintained closed.
Required ACTION a.3 verifies that an air lock with an inoperable door has been isolated by the use of a locked and closed OPERABLE air lock door.      This ensures that an acceptable containment leakage boundary is maintained.      The completion time of once per 31 days is based on engineering judgement and is considered adequate in view of the low likelihood of a locked door being mispositioned and other administrative controls.
ACTION a.3 allows the use of the air lock for entry and exit for 7 days under administrative controls if both air locks have an inoperable door.      This 7-day restriction begins when the second air lock is discovered to be inoperable.
SALEM - UNIT 2                    B 3/4 6-1b                      Amendment No.208   I

3/4.6 CONTAINMENT SYSTEMS BASES Containment entry may be required on a periodic basis to perform Technical Specification Surveillances and required ACTIONS, as well as other activities on equipment inside containment that are required by Technical Specifications or activities on equipment that support Technical Specification required equipment. This Note is not intended to preclude performing other activities (i.e.,   non-Technical Specification required activities) if the containment is entered, using the inoperable air lock, to perform an allowed entry listed above. This allowance is acceptable due to the low probability of an event that could pressurize the containment during the short time that the OPERABLE door is expected to be open.
Because of ALARA considerations, ACTION a.3 also allows air lock doors located in high radiation areas to be verified locked closed by use of administrative means.       Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted.
Therefore, the probability of misalignment of the door, once it has been verified to be in the proper position, is small.
With an air lock interlock mechanism inoperable in one or more air locks, the required ACTIONS and associated completion times are consistent with those specified in Condition a.        In addition, ACTION b.3 allows entry into and exit from containment under the control of a dedicated individual stationed at the air lock to ensure that only one door is opened at a time (i.e.,         the individual performs the function of the interlock).         In addition, ACTION b.3 allows air lock doors located in high radiation areas to be verified locked closed by use of administrative means.
ACTION c.1 requires that with one or more air locks inoperable for reasons other than those described in condition a. or b., action must be initiated immediately to evaluate previous combined leakage rates using current air lock test results.       An evaluation is acceptable, since it is overly conservative to immediately declare the containment inoperable if both doors in 0
an air lock have failed a seal test or if the overall air lock leakage is not within limits.      In many instances (e.g., only one seal per door has failed),
containment remains OPERABLE, yet only I hour (per LCO 3.6.1.1) would be provided to restore the air lock door to OPERABLE status prior to requiring plant shutdown.       In addition, even with both doors failing the seal test, the overall containment leakage rate can still        be within limits.
Required ACTION c.2 requires that one door in the affected containment air lock must be verified to be closed within the 1 hour completion time.          This specified time period is consistent with the ACTIONS of LCO 3.6.1.1, which requires that containment be restored to OPERABLE status within 1 hour.
Additionally, the affected air lock(s) must be restored to OPERABLE status within the 24 hour completion time.        This completion time begins at the time that the air lock is discovered to be inoperable.          The specified time period is considered reasonable for restoring an inoperable air lock to OPERABLE status, assuming that at least one door is maintained closed in each affected air lock.
If the inoperable containment air lock cannot be restored to OPERABLE status within the required completion time, the plant must be brought to a MODE in which the LCO does not apply.        To achieve this status, the plant must be brought to at least Hot Standby within 6 hours and to Cold Shutdown within the following 30 hours.       The allowed completion times are reasonable based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
SALEM - UNIT 2                         B 3/4 6-1c                    Amendment No. 208

CONTAINMENT SYSTEMS BASES Maintaining containment airlocks OPERABLE requires compliance with the leakage rate test requirements of 10CFR50, Appendix J, as modified by approved exemptions. This Surveillance Requirement reflects the leakage rate testing requirements with regard to air lock leakage (Type B leakage tests). The acceptance criteria were established during initial air lock and containment OPERABILITY testing. The periodic testing requirements verify that the air lock leakage does not exceed the allowed fraction of the overall containment leakage rate. The frequency is required by Appendix J, as'modified by approved exemptions. Thus, the provision of Specification 4.0.2 (which allows frequency extensions) does not apply.
The air lock interlock is designed to prevent simultaneous opening of both doors in a single air lock. Since both the inner and outer doors of an air lock are designed to withstand the maximum expected post accident containment pressure, closure of either door will support containment OPERABILITY. Thus, the door interlock feature supports containment OPERABILITY while the air lock is being used for personnel transit in and out of the containment. Periodic testing of this interlock demonstrates that the interlock will function as designed and that simultaneous opening of the inner and outer doors will not inadvertently occur. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
SALEM - UNIT 2                                B 3/4 6-1d                      Amendment No. 282 (PSEG Issued)

CONTAINMENT SYSTEMS BASES 3/4.6.1.4    INTERNAL PRESSURE The limitations on containment internal pressure ensure that:      1) the containment structure is prevented from exceeding its design negative pressure differential with respect to the outside atmosphere of 3.5 psig, and
: 2) the containment peak pressure does not exceed the design pressure of 47 psig during the limiting pipe break conditions.      The pipe breaks considered are LOCA and steam line breaks.
The limit of 0.3 psig for initial    positive containment pressure is consistent with the accident analyses initial     conditions.
The maximum peak pressure expected to be obtained from a LOCA or steam line break event is
* 47 psig.
3/4.6.1.5   AIR TEMPERATURE The limitations on containment average air temperature ensure that the overall containment average air temperature does not exceed the initial temperature condition assumed in the accident analysis for a LOCA or steam line break. In order to determine the containment average air temperature, an average is calculated using measurements taken at locations within containment selected to provide a representative sample of the overall containment atmosphere.
3/4.6.1.6    CONTAINMENT STRUCTURAL INTEGRITY This limitation ensures that the structural integrity of the containment will be maintained comparable to the original design standards for the life      of the facility. Structural integrity is required to ensure that the containment will withstand the design pressure.      The visual inspections of the concrete and liner and the Type A leakage test, both in accordance with the Containment Leakage Rate Testing Program, are sufficient to demonstrate this capability.
(Note that the elements of 3/4.6.1.7 were RELOCATED to 3/4 6.3 by LCR S06-06)
SALEM - UNIT 2                          B 3/4 6-2               Amendment No.260 (PSEG Issued)

CONTAINMENT SYSTEMS BASES 3/4.6.2   DEPRESSURIZATION AND COOLING SYSTEMS 3/4.6.2.1   CONTAINMENT SPRAY SYSTEM The OPERABILITY of the containment spray system, when operated in conjunction with the Containment Cooling System, ensures that containment depressurization and cooling capability will be available in the event of a LOCA. The pressure reduction and resultant lower containment leakage rate are consistent with the assumptions used in the accident analyses.
The containment spray system also provides a mechanism for removing iodine from the containment atmosphere and therefore the time requirements for restoring an inoperable spray system to OPERABLE status have been maintained consistent with that assigned other inoperable ESF equipment.
Normal plant operation and maintenance practices are not expected to trigger surveillance requirement 4.6.2.1.d. Only an unanticipated circumstance would initiate this surveillance, such as inadvertent spray actuation, a major configuration change, or a loss of foreign material control when working within the affected boundary of the system. If an activity occurred that presents the potential of creating nozzle blockage, an evaluation would be performed by the engineering organization to determine if the amount of nozzle blockage would impact the required design capabilities of the containment spray system. If the evaluation determines that the containment spray system would continue to perform its design basis function, then performance of the air or smoke flow test would not be required.       If the evaluation cannot conclusively determine the impact to the containment spray system, then the air or smoke flow test would be performed to determine if any nozzle blockage has occurred.
3/4.6.2.2   SPRAY ADDITIVE SYSTEM The OPERABILITY of the spray additive system ensures that sufficient NaOH is added to the containment spray in the event of a LOCA. The limits on NaOH volume and concentration, ensure that 1) the iodine removal efficiency of the spray water is maintained because of the increase in pH value, and 2) corrosion effects on components within containment are minimized.      The contained water volume limit includes an allowance for water not usable because of tank discharge line location or other physical characteristics.
These assumptions are consistent with the iodine removal efficiency assumed in the accident analyses.
3/4.6.2.3   CONTAINMENT COOLING SYSTEM The OPERABILITY of the containment cooling system ensured that adequate heat removal capacity is available when operated in conjunction with the containment spray systems during post-LOCA conditions.
The surveillance requirements for the service water accumulator vessels ensure each tank contains sufficient water and nitrogen to maintain water filled, subcooled fluid conditions in three containment fan coil unit (CFCU) cooling loops in response to a loss of offsite power, without injecting nitrogen covergas into the containment fan coil unit loops assuming the most limiting single failure. The surveillance requirement for the discharge valve response time test ensures that on a loss of offsite power, each discharge valve actuates to the open position in accordance with the design to allow sufficient tank discharge into CFCU piping to maintain water filled, subcooled fluid conditions in three CFCU cooling loops, assuming the most limiting single failure.
SALEM - UNIT 2                       B 3/4 6-3                     Amendment No. 270 (PSEG Issued)

CONTAINMENT   SYSTEMS BASES The surveillance requirements for the CFCUs ensure sufficient SWS flow through each operating cooler to provide the minimum containment cooling as assumed by the containment response analysis for a design-basis LOCA or MSLB event.      The surveillance flow rate is selected to ensure adequate heat removal (with no two-phase flow). The specified surveillance flow rate represents the total flow from both the CFCU coils and the CFCU motor-cooler 3/4.6.3    CONTAINMENT ISOLATION VALVES The OPERABILITY of the 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 pressurization of the containment. Containment isolation within the time limits specified ensures that the release of radioactive material to the environment will be consistent with the assumptions used in the analyses for a LOCA.
The opening of locked or sealed closed containment isolation valves (penetration flow paths) on an intermittent basis under administrative control includes the following considerations: (1) stationing a dedicated individual, who is in constant communication with the control room, at the valve controls, (2) instructing this individual to close these valves in an accident situation, and (3) assuring that the environmental conditions will not preclude access to close the valves and that this action will prevent the release of radioactivity outside the containment.
The main steam isolation valves (MSIVs) fulfill   their containment isolation function as remote-manual containment isolation valves.      The automatic closure of the MSIVs is not required for containment isolation due to having a closed system inside containment. The remote-manual containment isolation function of the MSIVs can be accomplished through either the use of the hydraulic operator or when the MSIV has been tested in accordance with surveillance requirement 4.7.1.5 the steam assist closure function can be credited.
Surveillance Requirement (SR) 4.6.3.3 only applies to the MS7 (Main Steam Drain) valves and the MS18 (Main Steam Bypass) valves.      The MS167 (Main Steam Isolation) valves are tested for main steam isolation purposes by SR 4.7.1.5.      For containment isolation purposes, the MS167s are tested as remote/manual valves pursuant to Specification 4.0.5.
3/4.6.4    COMBUSTIBLE GAS CONTROL The OPERABILITY of the equipment and systems required for the detection and control of hydrogen gas ensures that this equipment will be available to maintain the hydrogen concentration within containment below its flammable limit during post-LOCA conditions. Either recombiner unit is capable of controlling the expected hydrogen generation associated with 1) zirconium-water reactions, 2) radiolytic decomposition of water, and 3) corrosion of metals within containment.
These hydrogen control systems are consistent with the recommendations of Regulatory Guide 1.7, "Control of Combustible Gas Concentrations in Containment Following a LOCA," March 1971.
SALEM - UNIT 2                        B 3/4 6-4                  Amendment No. 270 (PSEG Issued)

CONTAINMENT SYSTEMS BASES containment purge supply and exhaust penetrations performs no containment integrity function in MODES 1-4; these valves operate during shutdown for normal system purging and containment closure when the blind flanges are removed.
SALRM - UNIT 2                     B 3/4 6-5                 Amendment No. S2008-084 (PSEG Issued)

3/4.7 PLANT SYSTEMS BASES 3/4.7.1 TURBINE CYCLE 3/4.7.1.1 SAFETY VALVES The OPERABILITY of the main steam line code safety valves ensures that the secondary system pressure will be limited to within 110% of its design pressure of 1085 psig during the most severe anticipated system operational transient. The MSSVs also provide protection against overpressurization of the Reactor Coolant Pressure Boundary by providing a heat sink for the removal of energy from the Reactor Coolant System if the preferred heat sink is not available. The maximum relieving capacity is associated with a turbine trip from 100% RATED THERMAL POWER coincident with an assumed loss of condenser heat sink (i.e., no steam bypass to the condenser).
The specified valve lift settings and relieving capacities are in accordance with the requirements of Section III of the ASME Boiler and Pressure Code, 1971 Edition. The total relieving capacity for all valves on all of the steam lines is 16.66 x 106 lbs/hr which is approximately 110% of the maximum calculated steam flow of 15.12 x 106 lbs/hr at 100%
RATED THERMAL POWER. A minimum of 2 OPERABLE safety valves per OPERABLE steam generator ensures that sufficient relieving capacity is available for the allowable THERMAL POWER restriction in Table 3.7-1.
STARTUP and/or POWER OPERATION is allowable with inoperable safety valves within the limitations of the ACTION requirements on the basis of the reduction in secondary steam flow associated with the required reduction of RATED THERMAL POWER. The acceptable power level (in percent RATED THERMAL POWER) for operation with inoperable safety valves was determined by performing explicit transient analysis.
The events that challenge the relief capacity of the safety valves are those resulting in decreased heat removal capability. In this category of events, a loss of external electrical load and/or turbine trip is the limiting anticipated operational occurrence. A series of cases was analyzed for this transient covering up to two inoperable safety valves on each steam generator.
The results of these cases were used to determine a maximum thermal power level from which the event could be initiated without exceeding the primary and secondary side design pressure limits. Thus, the maximum allowed power level as a function of the number of inoperable MSSVs on any steam generator is presented in Table 3.7-1. Note that the power level values presented on this table are the direct inputs into the transient analysis cases and do not include any allowance for calorimetric error. Actual power level reductions must include calorimetric uncertainty and other allowances for operating margin as deemed necessary.
Specific accident analyses for RCCA Bank Withdrawal at Power scenarios demonstrate that adequate safety valve relief capacity exist with up to two inoperable safety relief valves on each steam generator. These cases demonstrate that the reactor trip on OTDT along with the relief from the available main steam safety valves is sufficient to meet secondary side pressurization limits.
SALEM - UNIT 2                                  B 3/4 7-1                        Amendment No. 259 (PSEG Issued)

PLANT SYSTEMS BASES For three inoperable main steam safety valves in one or more steam generators, thermal reactor power must be reduced in conjunction with a reduction in the Power Range Neutron Flux High trip setpoint to prevent overpressurization of the main steam system.
The transient analysis assumes that the MSSVs will start to open at the lift setpoint with 3%
allowance for setpoint tolerance. In addition, the analysis accounts for accumulation by including a 5 psi ramp for the valve to reach its fully open position. Inoperable MSSVs are assumed to be those with the lowest lift setting. Surveillance testing as covered in Table 3.7-4 allows a +/- 3% lift setpoint tolerance. However, to allow for drift during subsequent operation, the valves must be reset to within +/- 1% of the lift setpoint following testing.
3/4.7.1.2 AUXILIARY FEEDWATER SYSTEM The OPERABILITY of the auxiliary feedwater system ensures that the Reactor Coolant System can be cooled down to less than 350'F from normal operating conditions in the event of a total loss of offsite power.
Verifying that each Auxiliary Feedwater (AFW) pump's developed head at the flow test point is greater than or equal to the required minimum developed head ensures that the AFW pump performance has not degraded during the cycle, and that the assumption made in the accident analysis remain valid. Flow and differential head are normal tests of centrifugal pump performance required by Section Xl of the ASME Code. Because it is undesirable to introduce cold AFW into the steam generators while operating, the test is performed on recirculation flow.
This test confirms one point on the pump design curve (head vs flow curve), and is indicative of pump performance. Inservice testing confirms pump operability, trends performance and detects incipient failures by indication of pump performance.
The flow path to each steam generator is ensured by maintaining all manual maintenance valves locked open. A spool piece consisting of a length of pipe may be used as an equivalent to a locked open manual valve. The manual valves in the flow path are: 2AF1, 21AF3, 22AF3, 23AF3, 21AF10, 22AF10, 23AF10, 24AF10, 21AF20, 22AF20, 23AF20, 24AF20, 21AF22, 22AF22, 23AF22, 24AF22, 21AF86, 22AF86, 23AF86, and 24AF86.
LCO 3.0.4.b is not applicable to an inoperable AFW train. There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an AFW train inoperable. The provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.
3/4.7.1.3 AUXILIARY FEED STORAGE TANK The OPERABILITY of the auxiliary feed storage tank with the minimum water volume ensures that sufficient water is available to maintain the RCS at HOT STANDBY conditions for 8 hours with steam discharge to the atmosphere concurrent with total loss of offsite power. The contained water volume limit includes an allowance for water not usable because of tank discharge line location or other physical characteristics.
SALEM - UNIT 2                                B 3/4 7-2                         Amendment No. 258

PLANT SYSTEMS BASES 3/4.7.1.4 ACTIVITY The limitations on secondary system specific activity ensure that the resultant offsite radiation dose will be limited to a small fraction of 10 CFR Part 100 limits in the event of a steam line rupture. This dose also includes the effects of a coincident 1.0 GPM primary to secondary tube leak in the steam generator of the affected steam line. These values are consistent with the assumptions used in the accident analyses.
3/4.7.1.5 MAIN STEAM LINE ISOLATION VALVES The OPERABILITY of the main steam line isolation valves ensures that no more than one steam generator will blowdown in the event of a steam line rupture. This restriction is required to
: 1) minimize the positive reactivity effects of the Reactor Coolant System cooldown associated with the blowdown, and 2) limit the pressure rise within containment in the event the main steam line rupture occurs within containment. The OPERABILITY of the main steam isolation valves within the closure times of the surveillance requirements are consistent with the assumptions used in the accident analyses.
If the closure time of the main steam isolation valve (MSIV) during technical specification surveillance testing (performed at a Steam Generator pressure between 800 psig and 1015 psig) is 5.0 seconds or less and the engineered safety feature response time (including valve closure time) for the steam line isolation (MSI) signal (Table 3.3-5) is 5.5 seconds or less, then assurance is provided that MSI occurs within 12 seconds under accident conditions, where Steam Generator pressure may be lower. This method of testing assures that for main steam line ruptures that are initiated from Modes 1-3 conditions that generate a MSl signal via automatic or manual initiation and have adequate steam line pressure to close, the main steam lines isolate within the time required by the accident analysis. Fast closure of the MSIVs is assured at a minimum steam pressure of 170 psia. However, the MSIV will still close via the steam assist function between 118 - 170 psia with slightly greater closure times. For main steam line ruptures that receive an automatic or manual signal for MSI and do not have adequate steam pressure to close the MSIVs (less than 118 psia), the event does not require MSIV closure to provide protection to satisfy design basis requirements (e.g., minimum DNBR remains above the minimum DNBR limit value and peak containment pressure remains below 47 psig).
Testing for SR 4.7.1.5 is performed prior to opening the MSIVs for power operation.
During testing, only one valve is opened at a time, with the other three valves remaining closed in the safe position, ensuring isolation capability is maintained. In the event of a steam line rupture, a postulated failure of the tested valve in the open position would result in the blowdown of a single steam generator since the remaining three MSIVs are closed. Failure of a single MSIV to close is consistent with the accident analysis assumptions for a major secondary system pipe rupture (UFSAR Section 15.4.2).
SALEM - UNIT 2                                  B 3/4 7-3         Revised by letter dated 6-19-2003

PLANT SYSTEMS BASES 3/4.7.2 STEAM GENERATOR PRESSURE/TEMPERATURE LIMITATION The limitation on steam generator pressure and temperature ensures that the pressure induced stresses in the steam generators do not exceed the maximum allowable fracture toughness stress limits. The limitations of 70&deg;F and 200 psig are based on average steam generator impact values taken at 10&deg;F and are sufficient to prevent brittle fracture.
3/4.7.3 COMPONENT COOLING WATER SYSTEM The OPERABILITY of the component cooling water system ensures that sufficient cooling capacity is available for continued operation of safety-related equipment during normal and accident conditions. The component cooling water system (CCW) consists of two safeguards mechanical trains supplied by three pumps powered from separate vital buses. This complement of equipment assures adequate redundancy in the event of a single active component failure during the injection phase. Operability of the CCW system exists when both mechanical trains and all three CCW pumps are operable.
3/4.7.4 SERVICE WATER SYSTEM The OPERABILITY of the service water system ensures that sufficient cooling capacity is available for continued operation of safety-related equipment during normal and accident conditions. The redundant cooling capacity of this system, assuming a single failure, is consistent with the assumptions used in the accident conditions within acceptable limits.
SALEM - UNIT 2                  B 3/4 7-4           March 7, 1997                           I

PLANT SYSTEMS BASES 3/4.7.5 FLOOD PROTECTION The limitation on flood protection ensures that facility protective actions will be taken and operation will be terminated in the event of flood conditions. The limit of elevation 10.5' Mean Sea Level is based on the elevation above which facility flood control measures are required to provide protection to safety-related equipment.
3/4.7.6 CONTROL ROOM EMERGENCY AIR CONDITIONING SYSTEM BACKGROUND:
The control room emergency air conditioning system (CREACS) provides a protected environment from which occupants can control the unit following an uncontrolled release of radioactivity, hazardous chemicals, or smoke.
The OPERABILITY of the CREACS ensures that 1) the ambient air temperature does not exceed the allowable temperature for continuous duty rating for the equipment and instrumentation cooled by this system and 2) the control room will remain habitable for operations personnel during and following all credible accident conditions.
The CREACS consists of two independent, redundant trains, one from each unit that re-circulate and filter the air in the Control Room Envelope (CRE) and a CRE boundary that limits the inleakage of unfiltered air. Each CREACS train consists of a prefilter, a high efficiency particulate air (HEPA) filter, an activated charcoal adsorber section for removal of gaseous activity (principally iodines), and fans. Ductwork, valves or dampers, doors, barriers, and instrumentation also form part of the system. The CREACS is a shared system between Unit 1 and 2 supplying a common CRE. During emergency operation following receipt of a Safety Injection or High Radiation actuation signal, for areas inside the CRE, one 100% capacity fan in each Unit's CREACS will operate in a pressurization mode with a constant amount of outside air supplied for continued CRE pressurization. One fan from each train will automatically start upon receipt of an initiation signal, with one fan in each train in standby. A failure of one fan will result in the standby fan automatically starting.
Each CREACS train has two 100% capacity fans, such that any one of the four fans is sized to provide the required flow for CRE pressurization within the common CRE during an emergency.
A failure of one CREACS filtration train requires manual actions to properly reposition dampers in support of single filtration train operation.
To minimize control room radiological doses, the CREACS outside air is supplied from the non-accident unit's emergency air intake through the cross-connected supply duct (as determined by which unit received an accident signal). Outside air is mixed with recirculated air, passed through each CREACS filter bank (pre-filter, HEPA filter, and charcoal adsorber) and cooling coil, and distributed to the common CRE. The CREACS is designed to maintain a habitable environment in the CRE for 30 days of continuous occupancy after a Design Basis Accident (DBA) without exceeding 5 Rem total effective dose equivalent (TEDE).
SALEM - UNIT 2                                  B 3/4 7-5                        Amendment No. 269 (PSEG Issued)

PLANT SYSTEMS BASES The CREACS is an emergency system, parts of which may also operate during normal unit operations in the standby mode of operation. Upon receipt of the actuating signal(s), normal air supply to the CRE is isolated, and the stream of ventilation air is recirculated through the system filter trains. The prefilters remove any large particles in the air to prevent excessive loading of the HEPA filters and charcoal adsorbers. Pressurization of the CRE minimizes infiltration of unfiltered air through the CRE boundary from all the surrounding areas adjacent to the CRE boundary. CREACS will be manually initiated in the recirculation mode only in the event of a fire outside the CRE, a toxic chemical release, or testing.
The CRE is the area within the confines of the CRE boundary that contains the spaces that control room occupants inhabit to control the unit during normal and accident conditions.
This area encompasses the control room and other non-critical areas to which frequent personnel access or continuous occupancy is not necessary in the event of an accident. The CRE is protected during normal operation, natural events, and accident conditions. The CRE boundary is the combination of walls, floor, roof, ducting, doors, penetrations and equipment that physically form the CRE. The OPERABILITY of the CRE boundary must be maintained to ensure that the inleakage of unfiltered air into the CRE will not exceed the inleakage assumed in the licensing basis analysis of design basis accident (DBA) consequences to CRE occupants.
The CRE and its boundary are defined in the Control Room Envelope Habitability Program.
APPLICABLE SAFETY ANALYSES The CREACS components are arranged in redundant, safety related ventilation trains.
The location of components and ducting within the CRE ensures an adequate supply of filtered air to all areas requiring access. The CREACS provides airborne radiological protection for the CRE occupants, as demonstrated by the CRE occupant dose analyses for the most limiting design basis accident, fission product release presented in the UFSAR, Chapter 15.
The CREACS 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, as described in UFSAR, Section 6.4. 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, as described in UFSAR, Section 9.5.
SALEM - UNIT 2                                 B 3/4 7-5a                           TSBC S2011-238

PLANT SYSTEMS BASES LCO Two independent and redundant CREACS trains are required to be OPERABLE to ensure that at least one is available if a single active failure disables the other train. Total system failure, such as from a loss of all ventilation trains or from an inoperable CRE boundary could result in exceeding a dose of 5 rem TEDE to the CRE occupants in the event of a large radioactive release.
In order for the CREACS trains 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 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 are 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.
A significant contributor to this system's OPERABILITY are the dampers, which are required to actuate to their correct positions. The following dampers are associated with the respective LCO*:
a.1     Fan outlet dampers: 1(2)CAA15 and 1(2)CAA16 These dampers ensure that the flow path for CREACS is operable and are required to open upon CREACS initiation. The associated fan outlet damper will open on fan operation.
a.4     Return air isolation damper: 1(2)CAA17 When aligned for single train operation, the associated air return isolation damper will be administratively controlled in the open position.
: b.      Other dampers required for automatic operation in the pressurization or recirculation modes:
Control Area Air Conditioning System (CAACS) outside air intake isolation dampers:
1(2)CAA40, 1(2)CAA41, 1(2)CAA43 and 1(2)CAA45 The normally open outside air intake dampers 1(2)CAA40 and inlet plenum isolation dampers 1(2)CAA43 will be closed under emergency conditions. The normally closed outside air intake dampers 1(2)CAA41 and inlet plenum isolation dampers 1(2)CAA45 are normally closed and remain closed under emergency conditions.
* Operability of the CREACS requires that each of the Unit 1 dampers are also operable SALEM - UNIT 2                                 B 3/4 7-5b                        Amendment No. 269 (PSEG Issued)

PLANT SYSTEMS BASES Control Area Air Conditioning System (CAACS) exhaust isolation dampers: 1(2)CAA18 and 1(2)CAA1 9.
These dampers are normally closed and are required to remain closed to prevent inleakage from the outside environment in the event of a toxic release.
Control Room Emergency Air Conditioning System (CREACS) air intake dampers:
1(2)CAA48, 1(2)CAA49, 1(2)CAA50 and 1(2)CAA51 CREACS outside air intake dampers are maintained closed during normal and recirculation operation and are opened automatically upon initiation of CREACS pressurization.
The control logic will automatically open the CREACS air intake dampers farthest from the radiation source based upon which Unit's Solid State Protection System (SSPS) or Radiation Monitoring System (RMS) signal is received.
CAACS and CREACS interface isolation dampers: 1(2)CAA14 and 1(2)CAA20 These two dampers are normally open and do not have associated redundant dampers.
These dampers serve a boundary function by isolating the CREACS from the CAACS during emergency operation of the CREACS.
Note: Dampers 1(2)CAA5, CAACS recirculation damper will receive an accident alignment signal to ensure proper accident configuration of CAACS. This damper, however, is not required for the OPERABILITY of CREACS as defined in the LCO.
APPLICABILITY In all MODES and during movement of irradiated fuel assemblies, the CREACS must be OPERABLE to ensure that the CRE will remain habitable during and following a DBA.
During movement of irradiated fuel assemblies, the CREACS must be OPERABLE to cope with the release from a fuel handling accident, involving handling irradiated fuel.
SALEM - UNIT 2                               B 3/4 7-5c                      Amendment No. 269 (PSEG Issued) I

PLANT SYSTEMS BASES ACTIONS When one CREACS train is inoperable, for reasons other than an inoperable CRE boundary, action must be taken to align CREACS for single filtration train operation within 4 hours, and restore the inoperable filtration train to OPERABLE status within 30 days. In this Condition, the remaining OPERABLE CREACS train is adequate to perform the CRE occupant protection function. With CREACS aligned for single filtration train operation and with one of the two remaining fans or associated outlet damper inoperable, restore the inoperable fan or damper to OPERABLE status within 72 hours. However, the overall reliability is reduced because a failure in the OPERABLE CREACS train could result in loss of CREACS function.
The 72 hours completion time is based on the low probability of a DBA occurring during this time period, and ability of the remaining train components to provide the required capability.
If the unfiltered inleakage of potentially contaminated air past the CRE boundary and into the CRE can result in CRE occupant radiological dose greater than the calculated dose of the licensing basis analyses of DBA consequences (allowed to be up to 5 rem TEDE), or inadequate protection of CRE occupants from hazardous chemicals 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 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 hours to verify that in the event of a DBA, the mitigating actions will ensure that CRE occupant radiological exposures will not exceed the calculated dose of the licensing basis analyses of DBA consequences, and that CRE occupants are protected from hazardous chemicals and smoke. These mitigating actions (i.e., actions that are taken to offset the consequences of the inoperable CRE boundary) should be preplanned for implementation upon entry into the condition, regardless of whether entry is intentional or unintentional. The 24-hour completion time is reasonable based on the low probability of a DBA occurring during this time period, and the use of mitigating actions. The 90 day completion time 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 DBA. In addition, the 90 day completion time is a reasonable time to diagnose, plan and possibly repair, and test most problems with the CRE boundary.
In MODE 1, 2, 3, or 4, if the inoperable CREACS train or the CRE boundary cannot be restored to OPERABLE status within the required completion time, the unit must be placed in a MODE that minimizes accident risk. To achieve this status, the unit must be placed in at least MODE 3 within 6 hours, and in MODE 5 within the following 30 hours. The allowed completion times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.
SALEM - UNIT 2                                  B 3/4 7-5d                      Amendment No. 269 (PSEG Issued)

PLANT SYSTEMS BASES In MODE 5 or 6, or during movement of irradiated fuel assemblies, if the inoperable CREACS train cannot be restored to OPERABLE status, align CREACS for single filtration train operation within 4 hours, or suspend movement of irradiated fuel assemblies. With CREACS aligned for single filtration train operation with one of the two remaining fans or associated outlet damper inoperable, restore the fan or damper to OPERABLE status within 72 hours. The 72 hours completion time is based on the ability of the remaining train components to provide the required capability.
In MODE 5 or 6, or during the movement of irradiated fuel assemblies, with two CREACS trains inoperable or with one or more CREACS trains inoperable due to an inoperable CRE boundary, action must be taken immediately to suspend activities that could result in a release of radioactivity that might require isolation of the CRE. This places the unit in a condition that minimizes the accident risk. This does not preclude the movement of fuel to a safe position.
Immediate action(s), in accordance with the LCO Action Statements, means that the required action should be pursued without delay and in a controlled manner.
SURVEILLANCE REQUIREMENTS Standby systems should be checked periodically to ensure that they function properly.
TS Surveillance Requirement verifies that each fan is capable of operating for at least 15 minutes by initiating flow through the HEPA filter and charcoal adsorbers train(s) to ensure that the system is available in a standby mode. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
Filter testing verifies that the required CREACS testing is performed in accordance with the surveillance requirements. The surveillance requirements include testing the performance of the HEPA filter, charcoal adsorber efficiency, minimum flow rate, and the physical properties of the activated charcoal. Specific test Frequencies and additional information are discussed in detail in the surveillance requirements. Filter testing will be in accordance with the applicable sections of ANSI N510 (1975) with the exception that laboratory testing of activated carbon will be in accordance with ASTM D3803 (1989). The acceptance criteria for the laboratory testing of the carbon adsorber is determined by applying a minimum safety factor of 2 to the charcoal adsorber removal efficiency credited in the design basis dose analysis as specified in Generic Letter 99-02.
Actuation testing verifies that each CREACS train starts and operates on an actual or simulated actuation signal. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
SALEM - UNIT 2                                  B 3/4 7-5e                      Amendment No. 282 (PSEG Issued)

PLANT SYSTEMS BASES The control room envelope is considered intact and able to support operation of the CREACS when the emergency air conditioning system is capable of maintaining positive pressure with the control room boundary door(s) closed. Unfiltered air inleakage testing 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.
Each CAACS normal air intake ductwork has two radiation detector channels. The two detector channels from Unit 1 and Unit 2 CAACS air intake provide input to common radiation monitor processors. Each radiation monitor processor (one for 1R1B-1/1R1B-2 and one for 2R1B-1/2R1B-2) provides a signal to initiate CREACS in the pressurization mode should high radiation be detected. A minimum of one out of two detectors in either intake will initiate the pressurization mode. With two detector channels inoperable on a Unit, operation may continue as long as CREACS is placed in-service in the pressurization or recirculation mode. Pressurization mode will be initiated after 7 days with one inoperable detector. Radiological releases during a fuel handling accident while operating in the recirculation mode could result in unacceptable radiation levels in the CRE since the automatic initiation capability has been defeated for high radiation due to isolation of the detectors. Therefore, movement of irradiated fuel assemblies or Core Alterations at either Unit will not be permitted when in the recirculation mode.
The CRE is considered habitable when the radiological dose to CRE occupants calculated in the licensing basis analyses of DBA consequences is no more than 5 rem TEDE and the CRE occupants are protected from hazardous chemicals and smoke. The testing verifies that the unfiltered air inleakage into the CRE is no greater than the flow rate assumed in the licensing basis analyses of DBA consequences. When unfiltered air inleakage is greater than the assumed flow rate, CRE boundary is inoperable. Required action 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, which endorses, with exceptions, NEI 99-03, Section 8.4 and Appendix F. These compensatory measures may also be used as required mitigating actions. Options for restoring the CRE boundary to OPERABLE status include changing the licensing basis DBA consequence analysis, repairing the CRE boundary, or a combination of these actions. Depending upon the nature of the problem and the corrective action, a full scope inleakage test may not be necessary to establish that the CRE boundary has been restored to OPERABLE status.
SALEM - UNIT 2                                 B 3/4 7-5f                       Amendment No. 269 (PSEG Issued)

PLANT SYSTEMS BASES 3/4.7.7 AUXILIARY BUILDING EXHAUST AIR FILTRATION SYSTEM The Auxiliary Building Ventilation System (ABVS) consists of two major subsystems. They are designed to control Auxiliary Building temperature during normal and emergency modes of operation, and to contain Auxiliary Building airborne contamination (by maintaining slightly negative pressure) during Loss of Coolant Accidents (LOCA). The two subsystems are:
: 1.       A once through filtration exhaust system, designed to contain particulate and gaseous contamination and prevent it from being released from the building in accordance with 10CFR20, and
: 2.       A once through air supply system, designed to deliver outside air into the building to maintain building temperatures within acceptable limits. For the purposes of satisfying the Technical Specification LCO, one supply fan must be administratively removed from service such that the fan will not auto-start on an actuation signal; however, the supply fan must be OPERABLE with the exception of this administrative control.
These systems operate during normal and emergency plant modes. Additionally, the system provides a flow path for containment purge supply and exhaust during Modes 5 and 6. Either the Containment Purge system or the Auxiliary Building Ventilation System with suction from the containment atmosphere, with associated radiation monitoring will be available whenever movement of irradiated fuel is in progress in the containment building and the equipment hatch is open. If for any reason, this ventilation requirement can not be met, movement of fuel assemblies within the containment building shall be discontinued until the flow path(s) can be reestablished or close the equipment hatch and personnel airlocks.
Appropriate filtration surveillances are contained in the Updated Final Safety Analysis Report (UFSAR) Section 9.4.2.4, Test and Inspections. Auxiliary Building exhaust air filtration system functionality is not required to meet LCO 3.7.7..
The ventilation exhaust consists of three 50% capacity fans that are powered from vital buses. The fans are designed for continuous operation, to control the Auxiliary Building pressure at -0.10" Water Gauge with respect to atmosphere.
The ventilation supply consists of two 100% capacity fans that are powered from vital buses, and distribute outdoor air to the general areas and corridors of the building through associated ductwork.
SALEM - UNIT 2                                 B 3/4 7-5g                         TSBC SCN 06-015

PLANT SYSTEMS BASES 3/4.7.7 AUXILIARY BUILDING EXHAUST AIR FILTRATION SYSTEM (cont'd)
AUXILIARY BUILDING VENTILATION ALIGNMENT MATRIX NORMAL VENTILATION (Normal plant operations)*
Any two of the three exhaust fans and either of the two supply fans:
The normal alignment is two exhaust fans and one supply fan. During cooler seasons, and with the absence of the system heating coils, it may be required to limit the amount of colder outside air entering the building. In this case, it is acceptable to secure both supply fans from operation and reduce the number of operating exhaust fans to one.
There is sufficient capacity with the single exhaust fan to maintain the negative pressure within the auxiliary building boundary.
EMERGENCY VENTILATION (Emergency plant operation)
At least two of the three exhaust fans and either one of the two supply fans.
Note: During a Safety Injection (SI) all three exhaust fans and one of the supply fans will start.
This is acceptable and will maintain the boundary pressure while supplying the required cooling to the building. Should access/egress become difficult with the three exhaust fans running, one of the exhaust fans should be secured.
OPERABILITY of the Auxiliary Building Ventilation System ensures that air, which may contain radioactive materials leaked from ECCS equipment following a LOCA, is monitored prior to release from the plant via the plant vent.
Operation of this system and the resultant effect on offsite and control room dose calculations was assumed in the accident analyses. ABVS is discussed in UFSAR Section 9.4.2.
SALEM - UNIT 2                                B 3/4 7-5h                         Amendment No. 252

PLANT SYSTEMS BASES 3/4.7.8 SEALED SOURCE CONTAMINATION The limitations on removable contamination for sources requiring 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 or boron measuring devices) are considered to be stored and need not be tested unless they are removed from the shielded mechanism.
SALEM - UNIT 2                             B 3/4 7-5i                         Amendment No.209

PLANT SYSTEMS BASES 3/4.7.9 SNUBBERS All snubbers are required OPERABLE to ensure that the structural integrity of the reactor coolant system and all other safety related systems is maintained during and following a seismic or other event initiating dynamic loads. Snubbers excluded from the program are those installed on nonsafety related systems and then only if their failure or failure of the system on which they were installed, would have no adverse effect on any safety-related system.
The program for examination, testing and service life monitoring for snubbers is required to be performed in accordance with ASME BPV Code, Section XI or the OM Code and the applicable addenda as required by 10 CFR 50.55a(g) or 10 CFR 50.55a(b)(3)(v), except where the NRC has granted specific written relief, pursuant to 10 CFR 50.55a(g)(6)(i), or authorized alternatives pursuant to 10 CFR 50.55a(a)(3).
SALEM - UNIT 2                                B 3/4 7-6                         Amendment No. 284 (PSEG Issued)

3/4.7 PLANT SYSTEMS BASES THIS PAGE INTENTIONALLY BLANK (Material Deleted)
SALEM - UNIT 2                  B 3/4 7-7         Amendment No. 284 (PSEG Issued)

PLANT SYSTEMS 3/4.7.10 CHILLED WATER SYSTEM                -  AUXILIARY BUILDING SUBSYSTEM The OPERABILITY of the chilled water system ensures that the chilled water system will continue to provide the required normal and accident heat removal capability for the control room area, relay rooms, equipment rooms, and other safety related areas. Verification of the actuation of each automatic valve on a Safeguards Initiation signal includes actuation following receipt of a Safety Injection signal.
Removal of non-essential heat loads from the chilled water system in the event one chiller is inoperable ensures the remaining heat loads are within the heat removal capacity of the two operable chillers.
Removal of non-essential heat loads from the chilled water system in the event two chillers are inoperable and aligning the CREACs to the maintenance mode ensures the remaining heat loads are within the heat removal capacity of the operable chiller.
During chiller testing, operator actions can take the place of automatic actions During Modes 5 and 6 and during movement of irradiated fuel assemblies, chilled water components do not have to be considered inoperable solely on the basis that the backup emergency power source, diesel generator, is inoperable. This is consistent with Technical Specification 3.8.1.2 which only requires two operable diesel generators.
SALEM - UNIT 2                                   B 3/4 7-8                      Amendment No. 182

PLANT SYSTEMS BASES 3/4.7.11         FUEL STORAGE POOL BORON CONCENTRATION In the Maximum Density Rack (MDR) design, the spent fuel storage pool is divided into two separate and distinct regions. Region 1, with 300 storage positions, is designed to accommodate new fuel with a maximum enrichment of 4.25 wt% U-235. Unirradiated and irradiated fuel with initial enrichments up to 5.0 wt% U-235 can also be stored in Region 1 with some restrictions. These restrictions are stated in TS 3/4.7.12. Region 2, with 1332 storage positions, is designed to accommodate unirradiated and irradiated fuel with stricter controls as compared to Region 1. These controls are also stated in TS 3/4.7.12.
The water in the spent fuel storage pool normally contains soluble boron, which results in large subcriticality margins under actual operating conditions. However, the NRC guidelines, based upon the accident condition in which all soluble poison is assumed to have been lost, specify that the limiting keff of 0.95 be evaluated in the absence of soluble boron. Hence, the design of both regions is based on the use of unborated water, which maintains each region in a subcritical condition during normal operation with the regions fully loaded. The double contingency principle discussed in ANSI N-16.1-1975 and the USNRC letter of April 14, 1978, to all Power Reactor Licensees - OT Position for Review and Acceptance of Spent Fuel Storage and Handling Applications (Accession # 7910310568) allows credit for soluble boron under other abnormal or accident conditions, consistent with postulated accident scenarios. For example, the most severe accident scenario is associated with the abnormal location of a fresh fuel assembly of 5.0 wt% enrichment which could, in the absence of soluble poison, result in exceeding the design reactivity limitation (keff of 0.95). This could occur if a fresh fuel assembly of 5.0 wt% enrichment were to be inadvertently loaded into a Region 1 or Region 2 storage cell otherwise filled to capacity. To mitigate these postulated criticality related accidents, boron is dissolved in the pool water. Calculations for the worst case configuration confirmed that 800 ppm soluble boron (includes an appropriate allowance for boron concentration measurement uncertainty)is adequate to compensate for a mis-located fuel assembly. Subcriticality of the MDR with no movement of assemblies is achieved without credit for soluble boron and by controlling the location of each assembly in accordance with TS 3/4.7.12. Prior to movement of an assembly, it is necessary to verify the fuel storage pool boron concentration is within limit in accordance with TS 3/4.7.11.
Most postulated abnormal conditions or accidents in the spent fuel pool do not result in an increase in the reactivity of either MDR region. For example, an event that results in an increase in spent fuel pool temperature or a decrease in water density will not result in a reactivity increase. An event that results in the spent fuel pool cooling down below normal conditions does not impact the criticality analysis since the analysis assumes a water temperature of 4&deg;C. This assures that the reactivity will always be lower over the expected range of water temperatures.
SALEM - UNIT 2                                  B 3/4 7-9                         Amendment No.244

PLANT SYSTEMS BASES 3/4.7.11         FUEL STORAGE POOL BORON CONCENTRATION (continued)
However, accidents can be postulated that could increase the reactivity. This increase in reactivity is unacceptable with unborated water in the storage pool. Thus, for these accident occurrences, the presence of soluble boron in the storage pool prevents criticality exceeding limits in both regions. The postulated accidents are basically of three types. The first type of postulated accident is an abnormal location of a fuel assembly, the second type of postulated accident is associated with lateral rack movement, and the third type of postulated accident is a dropped fuel assembly on the top of the rack. The dropped fuel assembly and the lateral rack movement have been previously shown to have negligible reactivity effects (<0.0001 6k). The misplacement of a fuel assembly could result in Keff exceeding the 0.95 limit. However, the negative reactivity effect of a minimum soluble boron concentration of 600 ppm compensates for the increased reactivity caused by any of the postulated accident scenarios. The accident analyses are summarized in the FSAR Section 9.1.2.
The determination of 600 ppm has included the necessary tolerances and uncertainties associated with fuel storage rack criticality analyses. To ensure that soluble boron concentration measurement uncertainty is appropriately considered, additional margin is incorporated into the limiting condition for operation. As such, increasing the minimum required boron concentration in the fuel storage pool to 800 ppm conservatively covers the expected range of boron reactivity worth along with allowances associated with boron measurements.
The concentration of dissolved boron in the fuel storage pool satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii). The fuel storage pool boron concentration is required to be greater than or equal to 800 ppm. The specified concentration of dissolved boron in the fuel storage pool preserves the assumptions used in the analyses of the potential critical accident scenarios.
This concentration of dissolved boron is the minimum required concentration for fuel assembly storage and movement within the fuel storage pool.
This LCO applies whenever fuel assemblies are stored in the spent fuel storage pool, until a complete spent fuel storage pool verification has been performed following the last movement of fuel assemblies in the spent fuel storage pool. This LCO does not apply following the verification, since the verification would confirm that there are no misloaded fuel assemblies.
With no further fuel assembly movements in progress, there is no potential for a misloaded fuel assembly or a dropped fuel assembly.
SALEM - UNIT 2                                B 3/4 7-10                       Amendment No. 244

PLANT SYSTEMS BASES 3/4.7.11 FUEL STORAGE POOL BORON CONCENTRATION (continued)
The Required Actions are modified indicating that LCO 3.0.3 does not apply. Storage of fuel assemblies and the boron concentration in the spent fuel storage pool are independent of reactor operation. Therefore TS 3/4 3.7.11 and TS3/ 4 3.7.12 include the exception to LCO 3.0.3 to preclude an inappropriate reactor shutdown. When the concentration of boron in the fuel storage pool is less than required, immediate action must be taken to preclude the occurrence of an accident or to mitigate the consequences of an accident in progress. This is most efficiently achieved by immediately suspending the movement of fuel assemblies. The concentration of boron is restored simultaneously with suspending movement of fuel assemblies. Alternatively, beginning a verification of the fuel storage pool fuel locations, to ensure proper locations of the fuel, can be performed. However, prior to resuming movement of fuel assemblies, the concentration of boron must be restored. This does not preclude movement of a fuel assembly to a safe position.        If the LCO is not met while moving fuel assemblies in the spent fuel pool while in MODE 5 or 6, LCO 3.0.3 would not be applicable. If moving fuel assemblies in the spent fuel pool while in MODE 1, 2, 3, or 4, the fuel movement is independent of reactor operation. Therefore, inability to suspend movement of fuel assemblies is not sufficient reason to require a reactor shutdown.
This SR verifies that the concentration of boron in the fuel storage pool is within the required limit. As long as this SR is met, the analyzed accidents are fully addressed. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
SALEM - UNIT 2                                B 3/4 7-11                       Amendment No. 282 (PSEG Issued)

PLANT SYSTEMS BASES 3/4.7.12       FUEL ASSEMBLY STORAGE IN THE SPENT FUEL POOL In the Maximum Density Rack (MDR) design, the spent fuel storage pool is divided into two separate and distinct regions. Region 1, with 300 storage positions, is designed to accommodate new fuel with a maximum enrichment of 4.25 wt% U-235. Unirradiated and irradiated fuel with initial enrichments up to 5.0 wt% U-235 can also be stored in Region 1 with some restrictions. These restrictions are stated in TS 3/4.7.12. Region 2, with 1332 storage positions, is designed to accommodate unirradiated and irradiated fuel with stricter controls as compared to Region 1. These controls are also stated in TS 3/4.7.12.
The water in the spent fuel storage pool normally contains soluble boron, which results in large subcriticality margins under actual operating conditions. However, the NRC guidelines, based upon the accident condition in which all soluble poison is assumed to have been lost, specify that the limiting keff of 0.95 be evaluated in the absence of soluble boron. Hence, the design of both regions is based on the use of unborated water, which maintains each region in a subcritical condition during normal operation with the regions fully loaded. The double contingency principle discussed in ANSI N-16.1-1975 and the USNRC letter of April 14, 1978, to all Power Reactor Licensees - OT Position for Review and Acceptance of Spent Fuel Storage and Handling Applications (Accession # 7910310568) allows credit for soluble boron under other abnormal or accident conditions, since only a single accident need be considered at one time. For example, the most severe accident scenario is associated with the abnormal location of a fresh fuel assembly of 5.0 wt% enrichment which could, in the absence of soluble poison, result in exceeding the design reactivity limitation (keff of 0.95). This could occur if a fresh fuel assembly of 5.0 wt% enrichment were to be inadvertently loaded into a Region 1 or Region 2 storage cell otherwise filled to capacity, for any of the configurations. To mitigate these postulated criticality related accidents, boron is dissolved in the pool water. Calculations for the worst case configuration confirmed that 800 ppm soluble boron (includes an appropriate allowance for boron concentration measurement uncertainty) is adequate to compensate for a mis-located fuel assembly. Safe operation of the MDR with no movement of assemblies may therefore be achieved by controlling the location of each assembly in accordance with TS 3/4.7.12. Prior to movement of an assembly into a fuel assembly storage location in Region 1 or Region 2, it is necessary to perform SR 4.7.11 and either SR 4.7.12.1 or SR 4.7.12.2. In summary, before moving an assembly into the storage racks it is necessary to:
* validate that its final location meets the criticality requirements;
* and since there is a potential to misload the assembly, we need to ensure that the Fuel Storage Pool boron concentration is greater than the minimum required to preclude exceeding criticality limits prior to moving.
The configuration of fuel assemblies in the fuel storage pool satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).
SALEM - UNIT 2                                   B 3/4 7-12                       Amendment No.244

PLANT SYSTEMS BASES 3/4.7.12    FUEL ASSEMBLY STORAGE IN THE SPENT FUEL POOL (CONTINUED)
The restrictions on the placement of fuel assemblies within the spent fuel pool in accordance with TS 3/4.7.12, in the accompanying LCO, ensures the keff of the spent fuel storage pool will always remain < 0.95, assuming the pool to be flooded with unborated water.
This LCO applies whenever any fuel assembly is stored in Region 1 or Region 2 of the fuel storage pool.
The Required Actions are modified indicating that LC03.0.3 does not apply. Storage of fuel assemblies and the boron concentration in the spent fuel storage pool are independent of reactor operation. Therefore TS 3/4.3.7.11 and TS 3/4.3.7.12 include the exception to LCO 3.0.3 to preclude an inappropriate reactor shutdown. When the configuration of fuel assemblies stored in Region 1 or Region 2 of the spent fuel storage pool is not in accordance with TS 3/4.7.12, the immediate action is to initiate action to make the necessary fuel assembly movement(s) to bring the configuration into compliance with TS 3/4.7.12. If unable to move fuel assemblies while in MODE 5 or 6, LCO 3.0.3 would not be applicable. If unable to move fuel assemblies while in MODE 1, 2, 3, or 4, the action is independent of reactor operation.
Therefore, inability to move fuel assemblies is not sufficient reason to require a reactor shutdown.
The SR verifies by administrative means that the initial enrichment and burnup of the fuel assembly is in accordance with TS 3/4.7.12 in the accompanying LCO.
SALEM - UNIT 2                                B 3/4 7-13                        Amendment No.258

3/4.8 ELECTRICAL POWER SYSTEMS BASES 374.8.1 and.3/4.8.2 A.C. SOURCES AND ONSITE POWER DISTRIBUTION SYSTEMS The OPERABILITY of the A.C. and D.C power sources and associated distribution systems during operation ensures that sufficient power will be available to supply the safety related equipment required for 1) the safe shutdown of the facility, and 2) the mitigation and control of accident conditions within the facility. The minimum specified independent and redundant A'.C. and D.C. power sources and distribution systems satisfy the requirements of General Design Criterion 17 of Appendix "A" to 10 CFR Part 50.
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 consistent with the initial     condition assumptions of the accident analyses and are based upon maintaining at least two independent sets of onsite A.C.' and D.C. power sources and associated distribution systems OPERABLE during accident conditions coincident with an assumed loss of offsite power and single failure of one onsite A.C. source.
When a system or component is determined to be inoperable solely because its  emergency power source is inoperable, or solely because its normal power source is inoperable, it may still   be considered OPERABLE, provided the appropriate: Actions of 3.8.1.i.a.2, b.2 or d.2 are satisfied.
Action 3.8.1.1.a.2, which only applies if the train cannot be powered from an offsite source, is intended to provide assurance that an event coincident with a single failure of the associated DG will not result in a complete loss of safety function of critical redundant required systems.
Failure of a single offsite circuit will generally not, by itself,     cause any equipment to lose normal AC power. Action 3.8.1.1.b.2 is intended to provide assurance that a loss of offsite power, during the period that a DG is inoperable, does not result in a complete loss of safety function of critical systems. Action 3.8.1.1.d.2, which applies when two offsite circuits are inoperable,' is intended to provide assurance that an event with a coincident single failure will not result in a conplete loss of redundant required safety functions.
These systems are powered from the independent AC electrical power train. However, redundant required systems or components credited by this specification are not necessarily powered from AC electrical sources. For example, the single train turbine-driven auxiliary feedwater pump is redundant to the two:motor-driven pumps. Redundant required system or component failures consist of inoperable equipment associated with a train, redundant to the train that has an inoperable DG or offsite power.
LCO 3.0.4.b is not applicable to an inoperable DG. There is an increased risk associatediwith entering a MODE or other specified condition in the Applicability with an inoperable DG. The provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.
SALEM - UNIT 2                       B33/4 8-1                  Amendment No. 258

APPLICABILITY BASES The completion time for these actions is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This completion time also allows for an exception to the normal "time zero" for beginning the allowed outage time clock, starting only on discovery that both:
: a. One train has no offsite power supplying its loads, one Dr is inoperable or two required offsite circuits are inoperable; and
: b. A :required system or component on the other train is inoperable.
If at any time during these conditions a redundant required system or component subsequently becomes inoperable, this completion time begins to be tracked. Discovering no offsite power to one train of the onsite Class lE Electrical Power Distribution System, or one required DG inoperable, coincident with one or more inoperable required support or supported systems SALEM - UNIT 2                      B 3/4 8-1a                Amendment No. 258

3/4.8 ELECTRICAL POWER SYSTEMS
 .BASES (Continued) or components that are associated with the other train that has power, results in starting the completion times for the Action. The specified time is acceptablelbecause it minimizes risk while allowing time for restoration before subjecting the unit to transients associated with shutdown.
The remaining OPERABLE AC supplies (one offsite circuit and three DGs for Condition (a), two offsite circuits and two DGs for Condition (b), or three DGs for Condition (d)) are adequate to supply electrical power to the onsite Class 1E Distribution System. Thus, on a component basis, single failure protection for the required system or component's function may have been lost; however, function has not been lost. The completion time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required system or component. Additionally, the completion time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period. The completiontime for Condition d (loss of both offsite circuits) is reduced to 12 hours from that allowed for one train without offsite power (Action 3.8.1.1.a.2). The rationale is that Regulatory Guide 1.93 allows a completion~time of 24 hours for two required offsite circuits inoperable, based upon the assumption that two complete safety trains are OPERABLE. When a concurrentlredundant required system or component failure exists, this assumption is not the case, and a shorter completion time of 12 hours is
 .appropriate.
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*Applicability of specifications 3.8.2.2, 3.8.2.4, and 3.8.2.6 includes the movement of irradiated fuel assemblies. This will insure adequate electrical power is available for proper operation of the fuel handling building ventilation system during movement of irradiated fuel in the spent fuel pool.
An offsite circuit would be considered inoperable if it were not available to one required train. Although two trains are required by LCOs 3.8.2.2 and 3.8.2.4, the one train with offsite power available may be capable of supporting sufficient required features to allow continuation of CORE ALTERATIONS and irradiated fuel movement. By the allowance of the option to declare required features inoperable, with no offsite power available, appropriate restrictions will be implemented in accordance with the affected required features LCO's actions.
With the offsite circuit or diesel generator not available to all required trains, the option exists to declare all required features inoperable. Since
*this option may involve undesired administrative efforts, the allowance for sufficiently conservative actions is made. With both required diesel generators inoperable,.the minimum required diversity of AC power sources is not available. Therefore, it is required to suspend CORE ALTERATIONS,
.movement of irradiated fuel assemblies, and operations involving positive reactivity additions that could result in loss of required shutdown margin or boron concentration. Suspending positive reactivity additions that could result in failure to meet the minimum shutdown margin or boron concentration limit is required to assure continued safe operation.
SALEM - UNIT 2                       B 3/4 8-2                 Amendment No.246

3/4.8 ELECTRICAL POWER SYSTEMS BASES (Continued)
The Surveillance Requirements for demonstrating the OPERABILITY of the diesel generators are based upon the recommendations of Regulatory Guide 1.9, "Selection of Diesel Generator Set Capacity for Standby Power Supplies," March 10, 1971, 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. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program. Regulatory Guide 1.108 criteria for determining and reporting valid tests and failures, and accelerated diesel generator testing, have been superseded by implementation of the Maintenance Rule for the diesel generators per 10CFR50.65. In addition to the Surveillance Requirements of 4.8.1.1.2, diesel preventative maintenance is performed in accordance with procedures based on manufacturer's recommendations with consideration given to operating experience.
The minimum voltage and frequency stated in the Surveillance Requirements (SR) are those necessary to ensure the Emergency Diesel Generator (EDG) can accept Design Basis Accident (DBA) loading while maintaining acceptable voltage and frequency levels. Stable operation at the nominal voltage and frequency values is also essential in establishing EDG OPERATILITY, but a time constraint is not imposed. The lack of a time constraint is based on the fact that a typical EDG will experience a period of voltage and frequency oscillations prior to reaching steady state operation if these oscillations are not dampened out by load application. In lieu of a time constraint in the SR, controls will be provided to monitor and trend the actual time to reach stable operation within the band as a means of ensuring there is no voltage regulator or governor degradation that could cause an EDG to become inoperable.
"Standby condition" for the purpose of defining the condition of the engine immediately prior to starting for surveillance requirements requires that the lube oil temperature be between 100 OF and 170 OF. The minimum lube oil temperature for an OPERABLE diesel is 100 &deg;F.
The thirteen second time requirement for the Emergency Diesel Generator to reach rated voltage and frequency was originally based on a Westinghouse assumption of fifteen seconds that included the delay time between the occurrence of the incident and the application of electrical power to the first sequenced safeguards pump (BURL-301 1, dated November 13, 1974) and included an instrument response time of two seconds (BURL-1531, dated July 27, 1970). The times specified in UFSAR Section 15.4 bound the thirteen seconds specified in the TS.
The narrower band for frequency specified for testing performed in steady state isochronous operation will ensure the EDG will not be run in an overloaded condition (steady state) during accident conditions. Steady state is assumed to be achieved after one minute of operation in the isochronous mode with all required loads sequenced on the bus.
The narrower band for steady state voltage is specified for operation when the EDG is not synchronized to the grid to ensure the voltage regulator will protect driven equipment from over-voltages during accident conditions. Procedural controls will ensure that equipment voltages are maintained within acceptable limits during testing when paralleled to the grid.
The wider band for frequency is appropriate for testing done with the governor in the droop mode. Likewise the wider band for voltage is appropriate when paralleled to the grid.
SALEM - UNIT 2                                B 3/4 8-3                        Amendment No.282 (PSEG Issued)

3/4.8 ELECTRICAL POWER SYSTEMS BASES (Continued)
All voltages and frequencies specified in SR 4.8.1.1.2 are representative of the analytical values and do not account for postulated instrument inaccuracy. Instrument inaccuracies for EDG voltage and frequency are administratively controlled.
Preventive maintenance includes those activities (including pro-test inspections, measurements, adjustments and preparations) performed to maintain an otherwise OPERABLE EDG in an OPERABLE status. Corrective maintenance includes those activities required to correct a condition that would cause the EDG to be inoperable.
Surveillance requirement 4.8.1.2 is modified by a Note. The reason for the Note is to preclude requiring the OPERABLE DG(s) from being paralleled with the offsite power network or otherwise rendered inoperable during performance of the surveillance requirement, and to preclude de-energizing a required ESF bus or disconnecting a required offsite circuit during performance of surveillance requirements. With limited AC sources available, a single event could compromise both the required circuit and the DG. It is the intent that these surveillance requirements must still be capable of being met, but actual performance is not required during periods when the DG and offsite circuit are required to be OPERABLE.
During Startup, prior to entering Mode 4, the surveillance requirements are required to be completed if the surveillance frequency has been exceeded or will be exceeded prior to the next scheduled shutdown.
3/4.8.3 ELECTRICAL EQUIPMENT PROTECTIVE DEVICES Containment electrical penetrations and penetration conductors are protected by either deenergizing circuits not required during reactor operation or by demonstrating the OPERABILITY of primary and backup overcurrent protection circuit breakers during periodic surveillance.
The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.. Each manufacturer's molded case circuit breakers and lower voltage circuit breakers are grouped into representative samples which are then tested on a rotating basis to ensure that all breakers are tested. If a wide variety exists within any manufacturer's brand of molded case or lower voltage circuit breakers, it is necessary to further divide that manufacturer's breakers into groups and treat each group as a separate type of breaker for surveillance purposes.
Containment penetration conductor overcurrent protective device information is provided in the UFSAR.
SALEM - UNIT 2                                 B 3/4 8-4                       Amendment No. 282 (PSEG Issued)

3/4.9 REFUELING OPERATIONS BASES 3/4.9.1   BORON CONCENTRATION The limit on the boron concentration of the Reactor Coolant System (RCS), the refueling cavity, the fuel storage pool and the refueling canal during refueling ensures that the reactor remains subcritical during Mode 6.
Refueling boron concentration is the soluble boron concentration in the coolant in each of these volumes having direct access to the reactor core during refueling.
The soluble boron concentration offsets the core reactivity and is measured by chemical analysis of a representative sample of the coolant in each of the volumes. The refueling boron concentration limit is specified in the Core Operating Limits Report (COLR). Plant procedures ensure the specified boron concentration in order to maintain an overall core reactivity of Keff ! 0.95 during fuel handling, with control rods and fuel assemblies assumed to be in the most adverse configuration (least negative reactivity) allowed by plant procedures.
General Design Criterion 26 of 10CFR 50, Appendix A requires that two independent reactivity control systems of different design principles be provided. One of these systems must be capable of holding the reactor core subcritical under cold conditions. The Chemical and Volume Control System (CVCS) is the system capable of maintaining the reactor subcritical in cold conditions by maintaining the boron concentration.
The reactor is brought to shutdown conditions before beginning operations to open the reactor vessel for refueling. After the RCS is cooled and depressurized and the vessel head is unbolted, the head is slowly removed to form the refueling cavity. The refueling canal and the refueling cavity are then flooded with borated water from the refueling water storage tank through the open reactor vessel by gravity feeding or by the use of the Residual Heat Removal (RHR) System pumps. The fuel storage pool is also adjusted to the refueling boron concentration specified in the COLR.
The pumping action of the RHR System in the RCS and the natural circulation due to thermal driving heads in the reactor vessel and refueling cavity mix the added concentrated boric acid with the water in the refueling canal. The RHR System is in operation during refueling (see TS 3/4.9.8, OResidual Heat Removal (RHR) and Coolant Circulation - All Water levels, " and "Low Water Level") to provide forced circulation in the RCS and assist in maintaining the boron concentrations in the RCS, the refueling canal, and the refueling cavity above the COLR limit.
SALEM - UNIT 2                     B 3/4 9-1             Amendment No. 244

3/4.9 REFUELING     OPERATIONS BASES During refueling operations, the reactivity condition of the core is consistent with the initial      conditions assumed for the boron dilution accident in the accident analysis and is conservative for MODE 6.         The boron concentration limit specified in the COLR is based on the core reactivity     at the beginning of each fuel cycle (the end of refueling) and includes an uncertainty allowance. The required boron concentration and the plant refueling procedures that verify the correct fuel-loading plan (including full    core mapping) ensure that the Keff of the core will remain
< 0.95 during the refueling operation.        Hence, at least a 5% Ak/k margin of safety is established during refueling.        During refueling, the water volume in the spent fuel pool, the transfer canal, the refueling canal, the refueling cavity, and the reactor vessel form a single mass.        As a result   the soluble boron concentration is relatively       the same in each of these volumes.
The RCS boron concentration satisfies       Criterion 2 10CFR50.36(c) (2) (ii).
The LCO requires that a minimum boron concentration be maintained in the RCS, the refueling canal, the fuel storage pool and the refueling cavity while in MODE 6. The boron concentration limit specified in the COLR ensures that a core Keff S 0.95 is maintained during fuel handling operations.          Violation of the LCO could lead to an inadvertent criticality       during MODE 6.
This LCO is applicable in MODE 6 to ensure that the fuel in the reactor vessel will remain subcritical.       The required boron concentration ensures a Keff 5' 0.95.      A note to this LCO modifies the Applicability. The note states that the limits on boron concentration are only applicable to the refueling canal, the fuel storage pool and the refueling cavity when those volumes are connected to the Reactor Coolant System.        When the refueling canal, the fuel storage pool and the refueling cavity are isolated from the RCS, no potential path for boron dilution exists.       Above MODE 6, LCOs 3.1.1.1 and 3.1.1.2 ensure that an adequate amount of negative reactivity is available to shut down the reactor and maintain it      subcritical.
Continuation of CORE ALTERATIONS or positive reactivity additions (including actions to reduce boron concentration) is contingent upon maintaining the unit in compliance with the LCO.       If the boron concentration of any coolant volume in the RCS, the refueling canal, the fuel storage pool or the refueling cavity is less than its    limit, all operations involving CORE ALTERATIONS or positive reactivity additions must be suspended immediately.        Suspension of CORE ALTERATIONS and positive reactivity additions shall not preclude moving a component to a safe position.      Operations that individually add limited positive reactivity (e.g. temperature fluctuations from inventory addition or temperature control fluctuations), but when combined with all other operations affecting core reactivity (e.g., intentional boration) result in overall net negative reactivity addition, are not precluded by this action.
SALEM - UNIT 2                         B 3/4 9-1a             Amendment  No. 244

3/4.9 REFUELING OPERATIONS BASES In addition to immediately suspending CORE ALTERATIONS and positive reactivity additions, boration to restore the concentration must be initiated immediately. In determining the required combination of boration flow rate and concentration, no unique Design Basis Event must be satisfied. The only requirement is to restore the boron concentration to its required value as soon as possible. In order to raise the boron concentration as soon as possible, the operator should begin boration with the best source available for unit conditions. Once actions have been initiated, they must be continued until the boron concentration is restored. The restoration time depends on the amount of boron that must be injected to reach the required concentration.
The Surveillance Requirement (SR) ensures that the coolant boron concentration in the RCS, and connected portions of the refueling canal, the fuel storage pool and the refueling cavity, is within the COLR limits. The boron concentration of the coolant in each required volume is determined periodically by chemical analysis. Prior to reconnecting portions of the refueling canal, the fuel storage pool or the refueling cavity to the RCS, this SR must be met per SR 4.0.4. If any dilution activity has occurred while the cavity or canal was disconnected from the RCS, this SR ensures the correct boron concentration prior to communication with the RCS.
The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
3/4.9.2 INSTRUMENTATION The OPERABILITY of the source range neutron flux monitors ensures that redundant monitoring capability is available to detect changes in the reactivity condition of the core.
3/4.9.3 DECAY TIME The minimum requirement for reactor subcriticality prior to movement of irradiated fuel assemblies in the reactor pressure vessel ensures that sufficient time has elapsed to allow the radioactive decay of the short lived fission products. The 80-hour decay time (LAR S08-01) is consistent with the assumptions used in the fuel handling accident analyses and the resulting dose calculations using the Alternative Source Term described in Reg. Guide 1.183.
The minimum requirement for reactor subcriticality also ensures that the decay time is consistent with that assumed in the Spent Fuel Pool cooling analysis. The calendar based restrictions are established for the actual movement of irradiated fuel; i.e., movement cannot commence in the October 1 5th through May 1 5 th window unless at least 80 hours has elapsed since subcriticality was achieved. The 80 hour clock can start prior to October 15 but must end in the October 1 5 th - May 15th window for the 80 hour criteria to be applicable. Similarly, fuel movement between May 1 6 th and October 1 4 th cannot commence unless at least 168 hours has elapsed since subcriticality was achieved.
SALEM - UNIT 2                                B 3/4 9-1b                        Amendment No. 282 (PSEG Issued)

3/4.9    REFUELING OPERATIONS BASES Delaware River water average temperature between October 15th and May 15th is determined from historical data taken over 30 years.       The use of 30 years of data to select maximum temperature is consistent with Reg. Guide 1.27, "Ultimate Heat Sink for Nuclear Power Plants".
A core offload has the potential to occur during both applicability time frames. In order not to exceed the analyzed Spent Fuel Pool cooling capability to maintain the water temperature below 1800F, two decay time limits are provided. In addition, PSEG has developed and implemented a Spent Fuel Pool Integrated Decay Heat Management Program as part of the Salem Outage Risk Assessment.      This program requires a pre-outage assessment of the Spent Fuel Pool heat loads and heat-up rates to assure available Spent Fuel Pool cooling capability prior to offloading fuel.
3/4.9,4     CONTAINMENT BUILDING PENETRATIONS During     movement   of irradiated     fuel assemblies    within    containment  the requirements for containment building penetration closure capability and OPERABILITY ensure that a release of fission product radioactivity within containment will not exceed the guidelines and dose calculations described in Reg Guide 1.183, Alternative Radiological Source Term for Evaluating Design Basis Accidents at Nuclear Power Plants.            In MODE 6,    the potential for containment pressurization as a result of an accident is                  not likely.
Therefore,     the requirements to isolate the containment from the outside atmosphere can be less stringent.         The LCO requirements during movement of irradiated fuel assemblies within containment are referred to as "containment closure" rather than containment OPERABILITY.          For the containment to be OPERABLE,     CONTAINMENT INTEGRITY must be maintained.         Containment closure means that all potential release paths are closed or capable of being closed.
Closure restrictions include the administrative controls to allow the opening of both airlock doors and the equipment hatch during fuel movement provided that: 1) the equipment inside door or an equivalent closure device installed is capable of being closed with four bolts within 1 hour by a designated personnel; 2) the airlock doors are capable of being closed within 1 hour by designated personnel, 3) either the Containment Purge System or the Auxiliary Building Ventilation System taking suction from the containment atmosphere are operating and 4) the plant is in Mode 6 with at least 23 feet of water above the reactor pressure vessel flange.
Administrative requirements are established for the responsibilities and appropriate actions of the designated personnel in           the event of a Fuel Handling Accident      inside containment.       These requirements      include the responsibility to be able to communicate with the control room, to ensure that the equipment hatch is         capable of being closed,      and to close the equipment hatch and personnel airlocks within 1 hour       in  the   event of a fuel handling accident inside containment.        These administrative controls ensure containment closure will be established in accordance with and not to exceed the dose calculations performed using guidelines of Regulatory Guide 1.183.
SALEM - UNIT 2                       B 3/4 9-1c                 Amendment No. 273 (PSEG Issued)

REFUELING OPERATIONS BASES zl-=====          --------------------------==.====-----------------------=------
The containment serves to limit the fission product radioactivity that may be released from the reactor core following an accident, such that offsite radiation .exposures are maintained well within the requirements of 10CFR100 and Reg Guide 1.183, Alternative Source Term, as applicable. Additionally, the containment provides radiation shielding from the fission products that may be present in the containment atmosphere following accident conditions, The Containment Equipment Hatch, which Is part of the containment pressure boundary, provides a means for moving large equipment and components into or out of containment. During movement of irradiated fuel assemblies Within containment can be open provided that: 1) it is capable of being.closed with four bolts within 1 hour by designated personnel, 2) either the Containment Purge System or the Auxiliary Building Ventilation System taking suction from the containment atmosphere are operating and
: 3) the plant is in Mode 6 with at least 23 feet of water above the reactor pressure vessel flange. Good engineering practice dictates that the bolts required by the LCO are approximately equally spaced.
An equivalent closure device may be installed as an alternative to installing the Containment Equipment Hatch inside door with a minimum of four bolts. Such a closure device may provide penetrations for temporary services used to support maintenance activities inside containment at times when containment closure is'requlred; and may .be .installed In place of the Containment Equipment &#xfd;Hatch inside door or outside door. Penetrations Incorporated into the design of an equivalent closure device will be considered a part of the containment boundary and as such will be subject to the requirements of Technical Specification 3/4.9.4. Any equivalent closure device used to satisfy the requirements of Technical Specification 3/4.9.4.a will be designed, fabricated, installed, tested, and utilized In accordance with established procedures to ensure that the design requirements for the mitigation of a fuel handling accident during refueling operations are met. In case that this equivalent closure device is Installed In lieu of the equipment hatch inside door, the same restrictions and administrative controls apply to ensure closure will take place within 1 hour following a Fuel Handling Accident inside containment.
The containment air locks, which are also part of the containment pressure boundary, provide a means for personnel access during operation in MODES 1, 2, 3, and 4 as specified in LCO 3.6.1.3, "Containment Air Locks". Each air lock has a door at both ends. The doors are normally interlocked to prevent simultaneous opening when containment OPERABILITY Is required. During periods of unit shutdown, when containment closure Is not required and frequent containment entry is necessary, the air lock interlock mechanism may be disabled, This allows both doors of an airlock to remain open for extended periods. During movement of irradiated fuel assemblies within containment, containment closure may be required; therefore, the door. Interlock mechanism may remain disabled, and both doors of each containment airlook may be open If: 1) At least one door of each airlock is capable of being closed within 1 hour by dedicated personnel,) 2) either the Containment Purge System or the Auxiliary Building Ventilation System taking suction from the containment atmosphere are operating and 3) The plant is in Mode 6 with at least 23 feet of water above the reactor pressure vessel flange.
In the postulated FHA, the revised dose calculations performed using RG 1.183 criteria, do not assume automatic containment purge isolation thus allowing for continous monitoring of containment acitivity until the release pathways are isolated.. If required, manual isolation of containment purge can be initiated from the control room.
The other containment penetrations that provide direct access from containment atmosphere to outside atmosphere must be isolated. on at least one side. Isolation may be achieved by an OPERABLE automatic isolation valve, or by a manual isolation valve, blind flange, or equivalent: Equivalent isolation methods may include the use of a material that can provide a temporary atmospheric pressure, ventilation barrier. Any equivalent method used to satisfy the requirements of Technical Specification 3/4.9.4,c,1 will be designed, fabricated, Installed, tested, and utilized.in accordance with established procedures to ensure that the design requirements for the mitigation of a fuel handling accident during refueling operations are met.
SALEM - UNIT 2                                     6 3/4 9-2               Amendment No. 245

REFUELING OPERATIONS BASES The surveillance requirement 4.9.4.2 demonstrates that the necessary hardware, tools, and equipment are available to close the equipment hatch. The surveillance is performed once per refueling prior to the start of movement of irradiated fuel assemblies within the containment. This surveillance is only required to be met when the equipment hatch is open.
3/4.9.5 COMMUNICATIONS Deleted.
3/4.9.6 MANIPULATOR CRANE Deleted.
3/4.9.7 CRANE TRAVEL - SPENT FUEL STORAGE BUILDING Deleted.
3/4.9.8 RESIDUAL HEAT REMOVAL AND COOLANT CIRCULATION The requirements that at least one residual heat removal loop be in operation ensures that (1) sufficient cooling capacity is available to remove decay heat and maintain the water in the reactor pressure vessel below 140OF as required during the REFUELING MODE, and (2) sufficient coolant circulation is maintained through the reactor core to minimize the effects of a boron dilution incident and prevent boron stratification. A minimum flow rate of 1000 gpm is required. Additional flow limitations are specified in plant procedures, with the design basis documented in the Salem UFSAR. These flow limitations address the concerns related to vortexing and air entrapment in the Residual Heat Removal system, and provide operational flexibility by adjusting the flow limitations based on time after shutdown. The requirement to have two RHR loops OPERABLE when there is less than 23 feet of water above the reactor vessel flange ensures that a single failure of the operating RHR loop will not result in a complete loss of residual heat removal capability.
For support systems: Service Water (SW) and Component Cooling (CC), component redundancy is necessary to ensure no single active component failure will cause the loss of Decay Heat Removal. One piping path of SW and CC is adequate when it supports both RHR loops. The support systems needed before entering into the desired configuration (e.g., one service water loop out for maintenance in Modes 5 and 6) are controlled by procedures, and include the following:
       -  A requirement that the two RHR, two CC and two SW pumps, powered from two different vital buses be kept operable
       -  A listing of the active (air/motor operated) valves in the affected flow path to be locked open or disable.
SALEM - UNIT 2                                      B 3/4 9-3                        Amendment No. 277 (PSEG Issued)

REFUELING OPERATIONS BASES Note that four filled reactor coolant loops, with at least two steam generators with at least their secondary side water level greater than or equal to 5% (narrow range), may be substituted for one residual heat removal loop. This ensures that single failure does not cause a loss of decay heat removal.
With the reactor vessel head removed and 23 feet of water above the reactor pressure vessel flange, a large heat sink is available for core cooling. Thus, in the event of a failure of the operating RHR loop, adequate time is provided to initiate emergency procedures to cool the core.
3/4.9,9 (Not Used),
3/4.9.10 and 3/4/9/11 WATER LEVEL - REACTOR VESSEL AND 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. The minimum water depth Is consistent with the assumptions of the accident analysis.
3/4.9.12 FUEL HANDLING AREA VENTILATION SYSTEM The operability of the Fuel Handling Area Ventilation System during movement of Irradiated fuel ensures that a release of fission product radioactivity within the Fuel Handling Building will not exceed the guidelines and dose calculations described in Reg, Guide 1.183, Alternative Radiological Source Term for Evaluating Design Basis Accidents at Nuclear Power Reactors.
SALEM - UNIT 2                             B 3/4 9-4                                Amendment No. 245

3/4.10   SPECIAL TEST EXCEPTIONS BASES 3/4.10.1   SHUTDOWN MARGIN This special test exception provides that a minimum amount of control rod worth is imnmediately available for reactivity control when tests are performed for control rod worth measurement.       This special test exception is required to permit the periodic verification of the actual versus predicted core reactivity condition occurring as a result of fuel burnup or fuel cycling operations.
3/4.10.2    GROUP HEIGHT,  INSERTION,  AND POWER DISTRIBUTION LIMITS This Special test exception permits individual control rods to be positioned outside of their normal group heights and insertion limits during the performance of such PHYSICS TESTS as those required to 1) measure control rod worth, and 2) determine the reactor stability index and damping factor under xenon oscillation    conditions.
3/4.10.3    PHYSICS TESTS This special test exception permits PHYSICS TESTS to be performed at less than or equal to 5% of RATED THERMAL POWER with the Reactor Coolant System Tavg slightly lower than normally allowed so that the fundamental nuclear characteristics of the reactor core and related instrumentation can be verified. In order for various characteristics to be accurately measured, it is, at times, necessary to operate outside the normal restrictions of these Technical Specifications. For instance, to measure the moderator temperature coefficient at BOL, it is necessary to position the various control rods at heights which may not be allowed by Specification 3.1.3.5 which may, in turn, cause the RCS Tavg to fall slightly below the minimum 1
temperature of Specification 3.1.1.4.
3/4.10.4    NO FLOW TESTS 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.
SALEM - UNIT 2                          B 3/4 10-1              Amendment No. 206

3/4.11i  RADIOACTIVE EFFLUENTS BASES 3/4.11.1     LIQUID EFFLUENTS 3/4.11.1.1   Deleted 3/4.11.1.2   Deleted SALEM - UNIT 2                 B 3/4 11-1 Amendment No. 215

RADIOACTIVE EFFLUENTS BASES 3/4.11.1.3   Deleted S
3/4.11.1.4   LIQUID HOLDUP TANKS The tanks listed in this specification include all those outdoor 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.
SALEM - UNIT 2                       3 3/4 11-2              Amendment No. 215

RADIOACTIVE EFFLUENTS BASES 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 the limits of 10 CFR Part 20, Appendix B, Table I1, Column 2, at the nearest potable water supply and the nearest surface water supply in an UNRESTRICTED AREA.
3/4.11.2     GASEOUS EFFLUENTS 3/4.11.2.1   Deleted SALEM - UNIT 2                      B :3/4 11.-3            Amendment No. 215

RADIOACTIVE EFFLUENTS BASES 3/4.11.2.2  Deleted 3/4.11.2.3  Deleted I
SALEM - MIT 2         B 3/4 11-4 Amendmenxt No. 215

RADIOACTIVE  EFFLUENTS BASES 3/4.11.2.4  Deleted SALEM - UNIT 2        B 3/4 11-5 Amendment No. 215

RADIOACTIVE EFFLUENTS BASES 3/4.11.2.5   EXPLOSIVE GAS MIXTURE This specification is provided to ensure that the concentration of potentially explosive gas mixtures contained in the waste gas holdup system is maintained below the flammability limits of hydrogen and oxygen. Maintaining the concentration of oxygen below the specified values provides assurance that the releases of radioactive materials will be controlled in conformance with the requirements of General Design Criterion 60 of Appendix A to 10 CFR Part 50.
This specification is not applicable to portions of the Waste Gas System Removed from service for maintenance, provided that the portions removed for maintenance are isolated from sources of hydrogen and purged of hydrogen to less than 4% by'volume.
3/4.11.3   Deleted SALEM - UNIT 2                 B3/4 11-6          Amendment No. 243

RADIOACTIVE EFFLUENTS BASES 3/4.11.4  Deleted SALEM - UNIT 2       B 3/4 11-7 SALENIT2
                                   -         NO. 215 5 /41-7Amendment

RADIOACTIVE EFFLUENTS BASES 3/4.12  Deleted SALEM - UNIT 2        B 3/4 12-1 Amendment No. 215

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